The new year in Canadian natural gas exports is off to a shaky start, but strong domestic demand for underground oilsands production and reduced drilling are burning off surplus supplies.

Pipeline deliveries into the United States dropped by 6% to 240.8 Bcf during November, the first month of the traditional contract year tracked by Canada's National Energy Board (NEB). November exports were 256.1 Bcf in 2009.

The monthly average price fetched by Canadian gas at the international border dropped by 14% to US$3.82/MMBtu last November compared to US$4.47/MMBtu in the same month a year earlier, according to NEB's latest trade scorecard. The combination of reduced sales volumes and prices cut November export revenues by 19% to US$928.6 billion from US$1.15 billion for the same month of 2009.

But Canadian gas in storage -- as calculated by FirstEnergy Capital Corp., a Calgary-based investment house -- has dropped to 372 Bcf, down to a five-year low that is down by about 16% from the mid-winter level a year ago.

Canadian gas drilling remains depressed, with a majority of field activity aimed at oil for the first time in memory. But another key reason for the drop in gas inventories despite the deterioration of exports is suggested by Statistics Canada's economic accounts. The federal agency's latest records show that December 2010 gas sales on Canadian domestic markets rose by 1% to 10.3 Bcf/d from 10.2 Bcf/d compared to the same month a year earlier.

The increase emerged because growing industrial demand more than made up for drops of 5% in Canadian residential consumption and 6% in commercial use. Industrial gas sales grew by 7% to about 5.4 Bcf/d in December from 5 Bcf/d in the same month a year earlier.

The driving force in Canadian industrial demand growth is thermal oilsands projects that burn gas to make steam injections for extracting bitumen from deposits buried too deep for open-pit mining. Known as in-situ production, the thermal operations use an average of about 1 Mcf of gas for each barrel of oil output. The gas use often goes much higher, especially when production expansion is under way by aggressively heating up the deposits to start new bitumen wells flowing.

In-situ projects are living up to consensus forecasts that they will become the main oilsands growth front, eventually taking over from the Alberta resource's environmentally notorious northern mines a majority of total production that currently stands at about 1.5 million bbl a day.

As of last November the latest estimated bitumen output by thermal underground production sites exceeded 600,000 b/d after rising by nearly 140,000 b/d over the previous 12 months. Virtually all of a score of in-situ extraction operations are growing by adding new wells or improving the efficiency of old ones, or both.

Oil market trends are lighting a fire under thermal bitumen extraction. Not only have prices for all crude types risen -- the value of heavy grades from the Alberta oilsands has gone up extra fast. Discounts for bitumen compared to benchmark West Texas Intermediate -- known as the heavy-oil differential -- have shrunk into a range of 15-20% from the previous standard of 30-50%, thanks to reduced availability of light grades and export pipeline expansions that have widened the market for oilsands output.

There is also some consolation for natural gas exporters on current markets. The slippage in sales volumes, border prices and revenues at the outset of the 2010-2011 contract year is only about half as bad as the steep drops that the Canadian industry was experiencing 12 months earlier. The deterioration in the first month of the 2009-2010 period included plunges of 13% in export volumes to 256 Bcf from 294 Bcf, 31% in the average border price to US$4.47/MMBtu from US$6.45/MMBtu, and 40% in revenues to US$1.15 billion from US$1.9 billion.

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