Hardisty, an agricultural town of 700 people, has become a critically important logistics hub for Canada’s oil sands producers.

The town sits in a valley across from the largest concentration of oil storage facilities in Canada – a terminal city of more than 70 cylindrical tanks that occupy more land on the neighboring hilltop than the town itself in the valley below.

Enbridge, Gibson Energy and TransCanada each have the capacity to store millions of barrels of crude oil here, as do midstream companies like Inter Pipeline Fund, Plains Midstream Canada and Koch Industries Inc. subsidiary Flint Hills Resources LLC.

“We’ve asked them, ‘Why Hardisty?’” says Sandy Otto, the town’s finance officer, “and they’ve said, ‘We don’t really know why it all happened here.’”

Husky Energy Inc. also owns millions of barrels of storage capacity in the area – but as an oil producer, it is the exception.

The vast majority of the storage at Hardisty is rental storage, owned by midstream companies and rented out to producers.

At times when Canadian producers suffer price discounts for their crude relative to their American peers, the demand for storage in the area skyrockets.

And yet very few oil sands production companies choose to own their own storage, creating a physical hedge against oil price fluctuations, and the fluctuating demand for terminal space. Why not? The only place in North America with more oil storage capacity than Hardisty is Cushing, Oklahoma.

According to Kentucky-based advisory firm Genscape Inc., Cushing and Hardisty are the largest and best-used tank farms on the continent, followed by Patoka, Illinois; Midland, Texas; and Edmonton.

Additional storage terminals are planned for construction in both Hardisty and Cushing regardless of whether or not TransCanada’s proposed and long- delayed Keystone XL pipeline is approved; if built, it would link the two hubs through an 830,000-barrel-perday, 1,897-kilometer crude oil pipeline.

While Keystone XL might get all the attention, advisory firm EY’s energy leader Barry Munro says the storage-tank construction boom should be mainly attributed to the spike in unconventional oil production.

“We’re watching this dramatic recalibration of oil production across North America – significantly increased volumes everywhere,” he says. “That rewriting of the production profile across North America has put a great strain on all existing infrastructure.”

In response, midstream companies have led a storage boom at both Hardisty and Edmonton.

In 2009, Enbridge built 18 tanks in the small town. This year, Kinder Morgan Edmonton is building 3.6 million barrels of storage capacity, and the announcement of TransCanada’s Energy East pipeline to New Brunswick will mean new storage tanks get built in Hardisty.

Given that the Canadian Association of Petroleum Producers is expecting Albertan oil production to grow by 700,000 barrels per day by 2015, it’s unlikely these will satisfy the industry’s demand for storage.

Access to oil terminal capacity is becoming increasingly important for Albertan producers, though very few are choosing to invest in their own tanks. The primary reason for this is financial.

Munro says few producers choose to allocate their capital to building storage facilities because, in their view, the money is better spent ramping up production. “Those are the important capital allocation decisions that boards are faced with,” Munro says.

At present, midstream and infrastructure companies trade at a premium to pure exploration companies and, in fact, “Anybody dealing with infrastructure is trading at a premium to pure E&P companies and they do that even though their returns are lower.”

So why do so few producers own their own storage?

Munro says E&P companies that have significant investments sunk into storage assets have come to the same realization: they could drop their infrastructure assets into an investment vehicle – like a master limited partnership – and earn a return.

As a result, most production companies have steadily moved away from investing in storage capacity. But ballooning production and limited export options might cause some to reconsider.

“As soon as we saw that we had transportation constraints and started suffering significant price discounts on western Canadian prices versus West Texas Intermediate, everybody started saying, ‘How do I better manage my business so that I’m not a price taker?’” Munro says.

Driving the back roads around Hardisty’s tank farms reveals a who’s who of ownership in Alberta’s oil-storage wars:

• TransCanada is also prominently represented with 4.5 million barrels of capacity
• Larger producers like Husky Energy and, to a lesser extent, Canadian Natural Resources Ltd., have facilities in the area
• The Enbridge logo is painted on 18 terminals, and the company owns the most space in the area with 10.5 million barrels of capacity

But absent from the mix are any junior or intermediate producers’ logos, though undoubtedly their crude is flowing in and out of the midstream companies’ terminals on a daily basis.

At least one intermediate producer is shifting away from that business model.

MEG Energy Corp. is building six crude oil storage tanks north of Edmonton, which will give the company 900,000 barrels of oil storage capacity.

As of its last year-end, MEG’s liquids production averaged 28,773 bpd, which means it would take the company a month to fill those tanks on its own.

MEG spokesperson Brad Bellows says the company’s Stonefell terminal will “provide the ability to ride out short-term market fluctuations” and let the company sell its product on its own terms, at the best possible price.

After all, waiting for a few days or even a few hours can mean millions of dollars in lost or gained sales revenues. To MEG, the advantages of owning oil storage capacity extend beyond managing its own commodity prices.

The company seems to have deliberately built excess storage capacity, knowing that other producers are facing the same challenges. “If there are issues that cause other producers to store their product [at Stonefell terminal], we can do that,” Bellows says.

“If we can pick that up at opportune pricing, then we’ll do it.” Bellows also describes the Stonefell terminal as one piece in a larger infrastructure plan for MEG.

The company is also 50 per cent owner in the Access Pipeline, which stretches 345 kilometers between its Christina Lake in situ oil sands plant and ties directly into Stonefell.

And in December 2012, MEG announced that it had reached an agreement with Canexus Corp. to tie Stonefell to that company’s nearby oil-by-rail loading facility via pipeline.

The Canexus partnership will allow MEG to move up to 70,000 bpd, and Stonefell is a key part of that supply chain. “You just accumulate the hydrocarbons and then blend them or sell them at the appropriate tim ie, so rails going to play an important part of that,” Munro says. “Rail is a good example of how oil companies are starting to recognize the important need for infrastructure.”

Further, the terminal’s connection to adjacent pipelines gives MEG market options it wouldn’t otherwise have – MEG can send its oil west, east or south, wherever the highest bidder happens to be. Altogether, Bellows says, the comprehensive infrastructure plan “provides us access to all sorts of future markets.”

Pipeline Network

All pipelines responsible for delivering the majority of Alberta’s export-bound oil sands crude to outof- province markets connect at Hardisty:

• Enbridge’s Clipper
• Kinder Morgan’s Express
• Trans- Canada’s Keystone
• Inter Pipeline’s Bow River

Husky’s gathering systems in Cold Lake and Lloydminster feed into a pipeline connecting to Hardisty as well.

And if approved, TransCanada’s Keystone XL and Energy East pipelines will originate here too. The town’s importance came into sharp focus during the steep price differential that plagued Albertan oil sands producers last winter.

“If you think back to January, when [Western Canadian Select] was $40 under WTI, producers who had access to storage used it,” says Wood Mackenzie partner Skip York. “Then when the differential closed, they took those barrels back to market – that’s going to be the predominant hedging operation.”

But it’s not the only option for oil sands producers who also have light-oil production. York says that producers can choose to hedge their commodity risk in two different ways:

• They can hedge it physically (that is, through storage tanks)
• Or they can hedge that exposure financially in the futures markets for commodities

“There isn’t a forward curve for heavy crude like there is on the [New York Mercantile Exchange] for light sweet.

There’s some financial hedging that you can do with a heavy barrel, but not as much,” he says. “If you’re a heavy-oil guy, your financial option is going to exhaust itself much earlier than the guy hedging on NYMEX.”

This dual approach is nothing new.

Husky Energy’s presence in Hardisty is evidence of that, and so is the fact that Gibsons joint-ventured in 2012 with a large unnamed oil sands producer to purchase 2.3 million barrels of storage in town.

But that weak forward curve for heavy oil – combined with pipeline delays and rising unconventional oil production – explains part of the storage-tank build-out around Hardisty, and part of the reason MEG decided to invest in its own storage.

“It’s a bit unusual for a small producer to build storage other than in the field,” York says. “This is like a commercial or marketing terminal and it’s kind of unusual to see smaller independents doing what MEG is doing.”

There are more third-party storage options in the United States for junior and intermediate producers to physically hedge their barrels against price fluctuations.

In addition to the players with storage assets in Canada – like Enbridge, Plains All American and Kinder Morgan – producers in the U.S. can choose to store their barrels with Enterprise, Magellan Midstream or NuStar.

York says there have been 25 million barrels of storage added to Cushing alone since 2010. If capital wasn’t such a familiar constraint, EY’s Munro says, there might be more producers like MEG choosing to invest in storage.

How production companies decide to spend their capital, he says, is one of the great debates occurring in the industry today.

“In days gone by, when there was excess capacity, guys on the E&P side probably never thought they had to invest in storage so that you have some control,” Munro says.

And while that’s no longer the case, producers are cautious to invest in anything that doesn’t produce additional barrels. As Munro puts it: “Capital always flows to where it gets appropriately recognized.”

So far, that recognition hasn’t extended to intermediate-producer owned storage.