Belief that the bottom has been touched and the outlook can only improve for Canadian gas producers is showing even among professional skeptics and declared opponents of wishful thinking in petroleum engineering, geology and economics firms whose stock-in-trade is reserves evaluations.
The supply auditors -- led by Sproule Associates, GLJ Petroleum Consultants and AJM Petroleum Consultants -- are not yet ready to agree with a statement by Encana Corp. CEO Randy Eresman to impatient stockholders at his company's annual meeting last week that gas prices are "unsustainably low" (see Daily GPI, April 21). No analysts suggested Eresman is making a mistake by increasing Encana's budget for drilling into gas reserves steeped in liquid byproducts that fetch prices closer to oil.
But the emerging consensus is that the gas markets are unlikely to drop any farther and early signs of recovery are on the horizon. The North American glut brought on by shale supply development is expected to be offset by rising demand from growing Alberta thermal oilsands projects, gradual substitution of gas for coal as a preferred clean fuel at power stations and a developing expansion of Canadian export marketing to Asia.
At the most conservative end of the Canadian forecast spectrum, Sproule sees prices strengthening on Alberta's AECO trading hub modestly to annual averages of C$4.22/MMBtu in 2012 and C$4.51/MMBtu in 2013 (U.S. dollar figures are the same, with current economic consensus projecting the U.S. and Canadian exchange rate to stay at or close to par).
The wariest outlook puts the anticipated recovery three years away and expects only moderate rebounds to C$5.69/MMBtu in 2014 and C$5.97/MMBtu in 2015. Even 10 years from now, Canadian annual average prices are forecast to languish within a penny or three of C$6.00/MMBtu).
The outlook is tepid by the hot standard set at the last peak of the gas cycle in 2005, when the annual average hit C$9.20/MMBtu after hurricanes damaged Gulf of Mexico production and before shale production accelerated. But the picture is an improvement on the 2011 first quarter average of C$3.79/MMBtu and Sproule's estimate of an average C$3.71/MMBtu for the first nine months of this year.
More optimistic, GLJ sees gas averaging C$4.01/MMBtu on Alberta's AECO trading hub for 2011, followed by slow but steady recovery to C$4.74/MMBtu in 2012, C$5.31 in 2013, C$5.77 in 2014 and the C$8/MMBtu area 10 years from now. In GLJ's longer-range projections, the annual average is expected to rise by an annual average 2%.
AJM likewise incorporates brightening price expectations into its audits of Canadian producer reserves. The firm sees AECO gas holding steady at an average C$4.10/MMBtu for 2011 then gaining ground at a stately pace to C$4.60/MMBtu in 2012, C$5.20/MMBtu in 2013, C$5.50/MMBtu in 2014. A decade into the future, the AJM outlook anticipates Canadian annual average gas prices will return to the C$8.00 area.
Recently Calgary-based AltaCorp. Capital Inc.'s John Mawdsley wrote, "we believe [natural gas] will become the largest source of energy on the planet" (see Daily GPI, April 8).
By far the brightest light in current outlooks is cast by the prospect of Canadian production breaking out of North America and into Asian markets as a result of liquefied natural gas (LNG) export terminal projects on the Pacific coast of northern British Columbia (BC).
The first development -- Kitimat LNG by Apache Canada, EOG Resources Canada and Encana (see Daily GPI, March 21) -- receives a stellar rating from an economic analysis done by AJM. Counting associated BC pipeline capacity increases, the consulting house agrees with the project sponsors that completing the planned first, 600 MMcf/d stage of Kitimat LNG will cost about C$4.9 billion.
Breakeven prices for gas from the project's intended supply source -- the Horn River shale deposit in northeastern BC -- are calculated at C$3.00-6.00/MMBtu, depending on recoverable reserves achieved per well.
The entire investment -- LNG terminal, plus pipelines, plus wells -- is forecast to achieve an overall 10% return at prices of C$7-10.25/MMBtu, also depending on levels of success at using shale drilling methods in northern BC.
With efforts to apply the new production system in northern conditions still in trial pilot stages, the drilling technology is the biggest uncertainty in the BC LNG export plan's economics. The AJM analysis uses a wide range of recoverable reserves estimates of 5.5 to 13.5 Bcf per well, which in turn makes overall anticipated total supply costs -- counting wells, terminal and pipelines range -- from C$17.2 billion to C$32.2 billion.
But even in the lowest range of reserves expected per northern BC shale gas well, the scheme still breaks even, the analysis forecasts. "With recent commodity pricing in Asia hovering in the range of C$8.00-10/MMBtu, development of natural gas export capability presents Canada with a potentially tremendous economic opportunity," AJM says.
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