When Alison Redford was forced to admit last month that her province was running short of cash due to low oil prices, it was frightening for Alberta and worrisome for the entire nation. For the past decade, Canada has thrived on the good fortunes of the oil and gas industry, but those times, Redford made clear, are coming to an end. "Because of the rapidly growing levels of oil production in the United States and the fact that we've virtually nowhere else to sell our oil than the U.S. market, Alberta is getting just over $50 a barrel for our oil," Redford said. "This bitumen bubble means that the Alberta government will collect about $6 billion less in revenue this year alone. To put that in context, that's equivalent to all of our government spending on education each year."

Redford's fireside chat was intended to prepare citizens of her province for service cuts and possible tax increases expected on budget day, March 7. But the bitumen bubble's effect will reach far beyond the borders of the Wild Rose Province. Two weeks after Redford's remarks, federal Finance Minister Jim Flaherty told reporters lower government revenues follow from lower commodity prices like "night follows the day," meaning a hard line of spending as he approaches his own coming budget.

The price drop is an unexpected turn of events for an industry that for decades has operated under the assumption of Peak Oil--geophysicist M. King Hubbert's theory, first proposed in 1956, that the United States' then soaring oil production would peak and begin to decline around 1970. Hubbert was proven right within the century in which he lived. U.S. petroleum output peaked at 10 million barrels per day (bpd) in 1970, declined slightly, rose again in the 1980s as a result of the Prudhoe Bay discovery in Alaska, then declined again to around five million bpd in 2006. Over the same period, American oil consumption steadily grew-to more than 20 million bpd in 2007-with a larger share every year provided by imports.

Blessed as we are with the world's third-largest oil reserves, Canada's mission was to help fill America's growing gap between domestic supply and demand. All Canadian producers, already integrated into the U.S. market, had to do was finance exploration and development, and produce oil at market price, or even below it. Little thought was given to things like developing new markets or expanding distribution.

Unfortunately, that has left Canada's largest export industry ill-prepared for a world in which Hubbert's peak, at least in the short and medium term, no longer applies. American domestic production has been rising since 2006, thanks to innovations in extraction techniques that have enabled producers to get blood from stone in places like the Bakken formation in North Dakota and the Eagle Ford shale bed in Texas. At first gradual, the uptick is picking up speed; U.S. oil output rose three-quarters of a million bpd in 2012, the largest single-year increase in history. At the same time, consumption has been falling due to a still-sluggish economy, improved vehicle fuel efficiency and changing driving habits. America's need for imports is falling accordingly.

Now several eminent prognosticators can foresee a day when the U.S. becomes self-sufficient in energy. In November, the International Energy Agency, a Paris-based think-tank supported by energy-consuming developed nations, predicted the U.S. would surpass Saudi Arabia as the world's largest oil producer before 2020, and be self-sufficient in energy by 2035. The geopolitical implications are staggering, from undermining the influence of petro-states like Russia to curtailing western interests in the volatile Middle East.

Considering that Canada's oil and gas exports to the U.S., worth $92 billion in 2010, account for more than half of Canadian production of those commodities-and nearly a quarter of Canada's total merchandise exports-this is an ominous turn of events for Canada as well. As CIBC vice-chair Jim Prentice, a former federal environment minister, noted at a business forum in Lake Louise, Alta., in November, "a lot of assumptions have been based on the seemingly insatiable appetite of the United States for energy. And with the way the world is unfolding, we as Canadians can't build our prosperity on that assumption."

As recently as last June, the Canadian Association of Petroleum Producers projected the oilsands will yield five million bpd in 2030, up from around two million today. The prospect of self-sufficiency in the U.S., virtually our only export market at present, throws that projection into serious doubt. While it's unlikely Canadian producers will ever be shut out of the U.S. market entirely, they may have to fight just to maintain the level of sales they have now. "It's real simple," says Vincent Lauerman, a Canadian energy economist working in New York. "If your only export market is contracting, you'd better come up with some alternatives-especially if you think you'll be bringing on substantial new volumes."

The logical alternative market for Canada's energy-indeed the only one capable of absorbing the kind of volumes we're capable of producing-lies in Asia. The IEA expects China's energy demand to grow 60% by 2035, and India's to double. Hence the drive to build pipelines and export terminals to the Pacific Ocean is becoming for Canada's oil and gas industry an existential quest. "Speaking as an Albertan, we'd better get some major West Coast capacity opened by late this decade. Otherwise we're running into some serious problems," says Lauerman, senior oil markets economist with Energy Intelligence Group. "You either build the infrastructure to get it to markets, or you don't build those [oilsands] projects in the first place."

Recently retired Suncor Energy CEO Rick George echoed that theme in a speech to an Edmonton audience in January. "We need to move this oil in this great province of ours from its landlocked position to the Pacific coast," he said. "And we need a new pipeline to do it. Without an alternate export market, Canada could suffer a dramatic blow to its economy and its standard of living."

As it is, "we Canadians are leaving something close to $20 billion a year on the table in terms of the value we would get if we had full access to an open market. So that gets reflected back in taxes, both the provincial and federal coffers," George later told Canadian Business. "You can expect if we continue down this road, transfer payments will be affected by that, and that affects the standard of living of all Canadians. That's one thing that a lot of people across this country are only starting to realize."

The message is clear-if America doesn't want our energy, we need to find someone else who does. Making that happen will require not only a shift in our industry, but reconsideration of the fundamental assumptions that built the oilpatch.

THE CHANGE IN AMERICA'S OIL MARKET HAS COME on faster than just about anyone predicted. The increase in U.S. oil production since 2006 to 6.5 million bpd has resulted in a sudden pipeline capacity and pricing squeeze that only months ago was predicted to hit years in the future, if at all.

Think of the North American oil market as a basin or bowl. The refineries that buy crude oil and process it into products like gasoline and diesel have long been clustered around the edges, near the coasts. By and large, the finished product then flowed inland to the end users. There are a number of reasons for this. For starters, a refinery lasts 50 to 70 years; an oilfield gets depleted in 10 to 20 years. So there's little point in refining near the wellhead. You want to locate the refinery near two things: customers and the ocean. Near customers, because gasoline is much more volatile than crude oil; you don't want to transport it far or in large quantities if you can avoid it. And near the ocean, where you can always obtain oil off a tanker if local sources dwindle.

The layout of North American refining infrastructure also made sense as long as the U.S. was dependent on imports from Alaska, Mexico, Venezuela and the Middle East. However, that configuration is ill-suited to an era when the fastest-growing crude oil supply is coming from the middle of the bowl, from U.S. oil producers using new extraction techniques and the Canadian oilsands. According to a January report by IHS-CERA, 2.2 million bpd is currently coming from tight oil and 1.7 million from the oilsands. Already, there is insufficient pipeline capacity to pump it back from the middle of the bowl to the edges. The bowl, in other words, is filling up, and the backup leaves our producers struggling with lower prices. That's especially true for western Canadian producers, who wait behind North Dakota producers for limited pipeline capacity headed south.

While we haven't yet got to the point where Canadian oil production is literally stranded-shut down for lack of a place to store, let alone ship it-our product is selling for far less than the North American and world benchmark prices that continue to make filling up your car an expensive proposition. It's also below the break-even point for many oilsands and tight-oil operators. Were the price for Western Canadian Select to stay that low for months at a time, small or inadequately capitalized producers would have to consider halting operations.

Even some of the giants of the sands have pushed back on expansion plans, in some cases indefinitely. The oldest and largest operators in the oilsands, Suncor and Syncrude, both announced plans to cut their capital expenditures by 11% in 2013. Suncor is now reviewing its plans for its partially constructed Voyageur upgrader and the Fort Hills and Joslyn mines. Speaking to reporters upon his appointment as president and CEO of Total E&P Canada, a partner in the Fort Hills project, Andre Goffart hinted that this and other next-generation projects just don't make sense in the current cost environment. "We may need more time to optimize our projects," he said.

The belt-tightening is cascading down to the oilfield services sector. Edmonton-based North American Energy Partners blamed a 20% revenue decline and halving of earnings in the third quarter on project delays. "While we expect to see even further reduced demand in the oilsands for much of the remainder of the fiscal year, we believe we are taking the appropriate steps to help us remain profitable at lower volumes," president and CEO Martin Ferron said in a release. "These steps include organizational restructuring, cost reduction, debt repayment and the divestiture of certain non-core assets."

No longer can energy companies and their suppliers assume that the oilsands industry will just keep growing. New project development is slowing down now and could slow a lot more-possibly grind to a halt-depending on how pipeline plans to the Gulf Coast and the Pacific play out. "Production growth cannot occur unless some of the planned pipeline projects out of the Western Canadian Sedimentary Basin go ahead," asserted a TD Economics report in December. "Not doing so would create significant economic loss for the country." The Canadian Energy Research Institute estimated last year that pipeline constraints and resulting price discounts, if sustained, would cause the country to forego as much as $130 trillion in GDP and $276 billion in taxes from 2011 to 2035.

TO SEE WHAT COULD HAPPEN TO THE OIL SECTOR, many observers point to the situation now with natural gas. Years before they were widely applied to oil extraction, directional drilling and fracking transformed the gas business. The IEA expects the United States to become a net gas exporter in 2020,15 years before it becomes self-sufficient in energy overall. Many analysts think America's independence day in natural gas will arrive even sooner. "Last month, the U.S. produced 64.9 billion cubic feet a day, and that's getting pretty close to their overall consumption," says Dirk Lever, senior analyst with Altacorp Capital in Calgary. And it won't stop there. The U.S. Energy Information Administration expects gas output will rise another 44% by 2040.

The impact of the supply increase on North American natural gas prices has been dramatic. From a record high of nearly $16 per million British thermal units (BTU) in 2005 and a respectable $8 in 2008, gas has spent most of the past four years trading in the $2 to $3.50 range. Profits and share prices for gas producers have likewise crashed. Struggling just to break even, many capped their "dry" gas wells and focused on producing natural gas liquids such as butane and naphtha. Last year, their prices fell through the floor too.

Though not well recognized, natural gas's slide already has had a devastating impact on Canada. While Canada is the world's fifth-or sixth-largest oil producer, we're No. 3 in gas. But that standing is now threatened. "We've seen a large decline in Canadian gas production," says Patrick Reddy, Canadian equity analyst with Leith Wheeler Investment Counsel in Vancouver. Canada exported $35 billion worth of gas in 2005, supplying about one-sixth of the U.S. market. In 2011, that market share was down by half, and the income stream was down to $10 billion. Not only is less Canadian gas going south, but increasingly U.S. gas is coming north to Canada. Utilities in Ontario are buying gas from newly prolific suppliers in Ohio, Pennsylvania and West Virginia rather than Alberta.

This sad turn of events for gas is already affecting public finances in a big way. Until recently, gas was a much larger contributor to the Alberta treasury than the oilsands is or probably ever will be. After its $8-billion natural gas windfall in 2005-06, Premier Ralph Klein's government had so much money on its hands it gave away $400-so-called Ralph bucks-to every man, woman and child in the province.

Today, despite a generally buoyant economy, the Alberta government has fallen back into persistent deficit spending. What was budgeted to be a $886-million shortfall last spring has since swelled to a projected $3-billion deficit for 2012-13. Redford and Finance Minister Doug Horner are now hinting at the kind of restraint the province hasn't seen since the 1990s. If contract talks with teachers and health workers get hot in the next couple of years, blame natural gas prices.

British Columbia is likewise feeling the pinch, as what was looking like a shale gas boom little more than a year ago has gone quiet. Land sales that pulled in $2.7 billion in 2008 plunged to $139 million in 2012. The gas is there, quite possibly more than in Alberta-Apache Canada reported what it called "the most prolific shale gas resource test in the world" in B.C.'s Liard Basin a year ago-but at today's prices it's not worth drilling for.

THE OUTLOOK FOR OIL FACES THE SAME HEADWINDS, though the sky is not so dark, for a number of reasons. First of all, U.S. self-sufficiency in oil is neither as likely nor as imminent as in gas. Given the high cost of shale oil production, it's questionable much marginal new U.S. production will be able to displace established Canadian oilsands supply while also replacing production declines in California, Alaska and the Gulf of Mexico. Even the IEA takes care to note that North America, not the U.S. alone, will become a net exporter by 2030, and that U.S. production will begin dropping again by the late 2020s.

Second, oil's supply chains are complex; different refineries buy different grades of feedstock. Canadian producers of light oil and synthetic crude (oilsands product that has been through an upgrader) are the ones most threatened by the rise of shale oil and tight oil, with which they compete head to head. Not so producers of bitumen and heavy oil. Due to the conversion of some Midwestern refineries to heavy grades and improving pipeline access to heavy-grade refineries on the Gulf Coast, prices for these coarser crudes could in fact be on the way up.

Third, even an oil-independent America does not imply Canadian producers will be shut out of the marketplace. After all, Canada is oil independent, yet refineries in Quebec and the Atlantic provinces, lacking access to western Canadian oil, import crude from Algeria and the U.K. Subject to no tariffs and few other import restrictions, raw energy is a freely traded commodity that follows the dictates of the market.

And there are other markets than America's. In China especially, oil consumption is growing fast. By pouring more than $30 billion into the Canadian oilpatch in the past three years, Chinese investors have clearly signalled their interest in importing oil and gas from Canada. The only snag is a physical one: the lack of pipeline capacity to the Pacific coast.

As a result, many observers view the Canadian oilpatch's problem as simply one of infrastructure that the industry will find ways to solve. "Canadian oil has a market if it could only get to market," Lever says.

Others, however, point out that the solutions aren't so simple. "While the economics look attractive," TD Economics observed of pipeline prospects in December, "there is more to the world than economics." Intervening in regulators' and governments' decisions to permit new pipelines are environmental considerations and, in Canada, First Nations' desire to assert their territorial rights.

The huge ramp-up in oilsands production over the past decade-before the industry had worked out environmental bugs such as tailings disposal-helped environmentalists paint a bull's-eye on the industry's back, says Lauerman. "Most people here see the oilsands as some great evil," he says of his upstate New York neighbours.

Polls nonetheless suggest that a majority of Americans see high gasoline prices and oil imports from other, less friendly countries as equally great evils. This leaves proposed projects that would increase the flow from the oilsands to the U.S., such as Keystone XL, hanging in the balance. "There are a lot of political issues down here that could and would have an impact on how things play out in Canada," Lauerman says.

Either way, the short-term outlook for Canadian oil, price-wise, is grim. The long term is uncertain, in large part out of our hands. In the absence of megaproject solutions, there will be interim and incremental moves to improve market access. We've already seen significant use of railways to transport oil where the pipeline infrastructure is lacking, for example. There will also be more repurposing and redirection of old pipelines less likely to encounter resistance than greenfield projects. There may ultimately be reconfiguration of the refining industry in North America-expansions here, closures there, refitting for different grades-to better ration out the available feedstock.

But make no mistake, the prospect of American energy independence makes life harder for Canada's oil and gas industry. "From a business perspective," wrote Peter Tertzakian, chief economist at ARC Financial, last year, "each new barrel of oil must now compete for market share instead of being always guaranteed a top-dollar buyer." Successful companies will get the best price possible while working to constantly renew their social licence.

"Most importantly, they [must] run low-cost operations," Reddy says. After a decade in which soaring prices made just pumping more of the stuff the priority, the emphasis this decade will be on matching the cost of doing business to lower prices than producers have come to expect. Where they can't do that, Canada's vaunted energy bounty will simply stay in the ground.



BLOATED WITH NATURAL GAS AND NO RELIEF IN SIGHT

As they contend with plummeting demand in the United States, the sustaining hope for many in the natural gas business these days is the export of liquefied natural gas (LNG).

While rival suppliers, most notably Australia, are jumping into the LNG game, the demand in Asia is rising faster than the supply. China has more than quintupled its natural gas consumption since 2000. according to research firm GlobalData, and though the country has huge shale gas reserves of its own, production can't keep up. Its LNG importing capacity is projected to grow from around one trillion cubic feet per day in 2011 to 2.8 trillion in 2016. The Asian market, in other words, is more than big enough to replace the evaporating U.S. market.

At first blush, the business case for exporting LNG from B.C. to Asia looks hugely compelling. However, it takes massive capital expenditures to build the facilities to freeze natural gas down to -160°C and load it onto pressurized tankers, more than any producer can afford on its own. The largest facility, planned for Kitimat and led by Royal Dutch Shell in partnership with Mitsubishi, Korea Gas Co. and PetroChina, is expected to cost $12 billion.

To obtain financing for such a project, proponents need to nail down long-term supply contracts with Asian utilities. But customers have been unwilling to sign on the dotted line for two key reasons. The first is price. The proponents designed their plants assuming they could use a formula tied to world oil prices, but the buyers are demanding one tied to cheap North American gas prices.

The second stumbling block surrounds security of supply. Asian utilities want to know they'll get the gas the day the contract comes into effect. This explains why, for more than a year, the proponents of Canada's most advanced LNG proposal, Kitimat LNG, were unable to conclude a deal, and why, in late December, Chevron bought two of them out and became the project operator. The U.S. multinational already has LNG plants operating around the world. If the Kitimat plant is not running on time, customers may feel reassured Chevron can supply them from somewhere else.

While Chevron's takeover and BC LNG's contract move Canada closer to having an LNG industry, their experience suggests not all proposed LNG plants will get built in the first place, those that do will likely take longer than expected, and there will be hard bargaining between the suppliers in Canada and the buyers in Asia.

With reporting by Joe Castaldo

 

 


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