Lower Natural Gas Price Levels The New Normal?
This week’s drop in natural gas prices below the $5 US per thousand cubic foot mark has spurred a lot of chatter of whether this price level is the new normal for North America.
The answer, according to EnCana chief executive Randy Eresman, is that prices are likely to sit in the $6 range and that expecting any big price jumps is unrealistic.
Eresman was participating in a panel discussion at the annual natural gas conference hosted by the Canadian Energy Research Institute on Tuesday.
The recent sell-off in natural gas is being explained as a reaction to recent weather forecasts showing a warming trend south of the border, which means the amount in storage will exit the winter heating season ahead of the same time last year. As of last week, the storage numbers of 2.02 trillion cubic feet were 1.3 per cent greater than at this time last year and 2.7 per cent higher than the five-year average.
The natural gas business in North America is facing an embarrassment of riches as a result of technology that has unlocked shale gas deposits. And while it presents some short-term challenges — especially for Canadian producers that are at an immediate disadvantage because of their distance to major markets, Eresman also believes there are opportunities to be had.
The trick is creating the circumstances that will see a structural shift in how North America uses natural gas.
And, according to Eresman, while it’s going to be tough enough for U.S. natural gas producers, it’s even more challenging for Canadian companies because the cost structure is inherently higher even as the technology used to exploit the resources is the same on the both sides of the border.
What it means is that Canada’s natural gas industry has no choice but to become more competitive at everything from the regulatory process, the resource development costs, the toll mechanism of the pipeline companies transporting the commodity and, of course, the underlying fiscal structure.
In fact, according to Max Feldman, senior vice-president of TransCanada Corp., if Alberta were to adopt the royalty structure of British Columbia, it would boost production by one billion cubic feet per day over a 10-year period.
The fact the natural gas reserves in the Horn River and Montney plays are big enough to replace existing conventional production should be more than reason enough for the Alberta government to ensure the competitiveness review does enough to offset what is going on in B.C.
And, for a company such as TransCanada that has been grappling with a declining production curve, it’s tough to ignore those kinds of numbers.
The increasing shift toward unconventional — or resource plays — is also set to cause a shift in the structure of Canada’s oilpatch, particularly for the natural gas players.
For the better part of two decades, activity by junior oil and gas companies has been critical on a number of levels — whether exploiting assets sold off by bigger companies or doing the legwork on exploring and developing certain plays that are later sold to bigger companies; this was the primary source of growth of the royalty trusts.
But now, given the costs associated with the unconventional world, the yardsticks have moved.
“It’s a big company game because there are massive, upfront costs,” said Eresman.
The result will be a re-emergence of an intermediate-sized group of companies — not unlike what existed in the early 1990s before the adoption of the royalty trust structure in the oilpatch. It will leave juniors active in low-cost, conventional plays.
The fact natural gas prices are expected to stay in a tight range for the foreseeable future as a result of robust supply has also increased the likelihood there will be more incentive for switching from coal-fired power to natural gas.
In fact, one of the messages at the Canadian Energy Research Institute conference this week was that the outlook for natural gas has made the cost of building and operating natural gas power plants more competitive from a cost perspective than a coal-fired facility. And if one adds the environmental issues associated with coal-fired power, not to mention the cost of adding carbon capture and sequestration to the mix, using coal for power is even harder to justify.
Because natural-gas fired power is looking like an increasingly viable road to take in terms of effectively addressing two problems at once — that of reducing greenhouse gas emissions and boosting demand for a plentiful commodity — one of the possible outcomes is it could usher in a new era of long-term contracts between producers and users.
The challenge on this, said Eresman, is how to structure long-term supply contracts such that producers aren’t exposed if inflation becomes an issue, boosts costs and hangs them with terms that are under water.
Of course, this is a smattering of the variables that are bound to have an impact on the North American energy business; the only thing that is certain is the business of energy five years hence is going to be vastly different than the one we know today.
