By Robert Campbell
NEW YORK, Oct 18 (Reuters) - For years the energy story out of Canada has been exclusively about the emergence of Alberta’s oil sands as a massive, if costly new source of crude.
Indeed, the rise of the oil sands was always seen as a happy solution to the country’s dwindling conventional oil production and the crumbling economics of Alberta’s natural gas industry.
But a funny thing has been happening. The shale revolution has come to Canada’s oil sector in a big way. And like similar developments in the United States, the hottest play seems to be closely linked to the place where conventional oil production started decades ago.
As in Texas and Oklahoma, Alberta’s oil patch is seeing renewed interest in old acreage. Indeed, the latest transaction in the sector is aimed in part at the source rock - the Duvernay shale - of the famous Leduc No. 1 well that touched off Alberta’s postwar oil boom in 1947.
Exxon Mobil Corp’s proposed $2.6 billion acquisition of much of the assets of Canada’s Celtic Exploration instantly makes the supermajor a key player in both the Duvernay and the larger Montney shale.
Although the takeover is far too small to transform a company the size of Exxon, it speaks volumes about the shale potential in Alberta.
Indeed, the takeover is likely to force a lot of international companies to re-evaluate the potential of Alberta’s conventional oil sector.
Oil sands will remain huge, but could it be that cheaper and easier-to-develop shale oil captures the imagination?
Exxon tends to get acquisitions right, and the company’s reputation for long-term thinking means the Celtic buy has to be looked at strategically.
Celtic’s assets and current production are mostly gas-rich, but Exxon has played up the liquids angle in the transaction. That is the nature of most shale plays, though: They offer exposure to both oil and gas.
Although the longer-term picture for Western Canadian natural gas may improve with potential exports to Asia in the form of liquefied natural gas, the current picture is ugly and seems likely to stay that way for years.
Alberta’s natural gas sector is being squeezed by the shale revolution that is opening up production closer to its main markets in Eastern Canada and the U.S. Midwest.
That is hammering the economics of Albertan gas production, especially as dwindling volumes on major pipelines force up transportation tariffs.
On the other hand, both oil and natural gas liquids look far more promising.
Alberta is already a major petrochemical producer, and the oil sands require condensates for shipping. Therefore, anyone producing natural gas liquids and condensates in the province enjoys an advantage over producers who have to ship their product in by pipeline or rail.
Crude oil is similarly advantageous. Unlike more speculative plays, Alberta is an established oil center, replete with infrastructure and services.
That makes development cheaper and easier. Moreover Canada’s legal and regulatory regime is relatively stable, so that returns are more predictable.
But perhaps what most attracts Exxon is that Canada’s oil and gas industry suffers from a lot less of the political constraints that American producers face.
For all of the United States’ pretensions of supporting global free trade in energy, it is clear that crude oil exports from Texas and Oklahoma, however economically rational, are going to be politically controversial.
Natural gas exporters are also facing calls for restraint, notably from industrial users who hope to benefit from cheap fuel.
Canada, on the other hand, has a more coherent policy that favors energy producers. It wants to boost the price its producers receive by trying to build a pipeline to the Pacific, even in the face of local opposition in the province of British Colombia.
These should be the parameters for assessing the Celtic takeover. It is a transaction that gives Exxon exposure to non-oil sands crude and liquids in Canada as well as potential long-term upside from a recovery in Western Canadian gas prices.
It also raises interesting possibilities for future oil production. Could it be that Western Canada will be an even bigger producer a decade from now than currently believed if the conventional oil sector rebounds rather than declines?
And if so, where is this oil going to go? The last decade has shown just how challenging it has been for pipeline networks to adapt to the surge in oil sands crude and the surprise of North Dakota shale oil.
What if another shale oil giant bursts onto the scene?