CGP Numbers Show Little Chance of Quick End to High Prices

Abstract: An analysis by Oil & Gas Advisory of some of Canada's largest gas producers shows little reason for consumers to expect quick relief from high gas prices.

Analysis: The gas industry could have used Neil Armstrong this week as prices skyrocketed to highs not seen in more than two years.

And an analysis by Oil & Gas Advisory of some of Canada's largest gas producers shows little reason for consumers mooning for lower utility bills to expect to see any quick relief, particularly if U.S. gas storage levels drop below 700 billion cubic feet (bcf) at the end of March.

Oil & Gas Advisory crunched quarterly production numbers for 12 of Canada's largest gas producers. The firms, including such well-known players as Burlington Resources Inc., Devon Energy Corp., EnCana Corp., and Imperial Oil Ltd, account for just over half of the roughly 16 billion cubic feet per day (bcf/d) that flows out of Western Canada. The sample is large enough to draw some conclusions about production trends in the Western Canadian Sedimentary Basin.

Led by EnCana, the dozen firms pumped out 8.7 bcf/d in the fourth quarter, up 3.2 percent from the previous quarter. When compared to the final three months of 2001, the same companies managed to increase their daily output by 10 percent.

The seemingly encouraging numbers overstate the reality of a maturing basin, where producers have to drill more and more holes to hold production flat as natural declines in new wells average 25 per cent per year. Several companies, particularly in the year-over-year comparison of quarterly figures, bumped up their production last year as a result of acquisitions.

For example, Burlington's fourth-quarter numbers increased to 829 million cubic feet per day (mmcf/d) last year, up from 518 mmcf/d in the final three months of 2001. But Burlington spent $2.1 billion in late 2001 to buy Canadian Hunter Exploration Ltd., which was producing around 430 mmcf/d when purchased. Burlington's results become much less impressive after removing the contribution of Canadian Hunter.

Similarly, Canadian Natural Resources Ltd.'s 34 percent jump in its fourth-quarter gas volumes, which rose to 1.3 bcf/d, was enhanced by its C$2.4 billion purchase of Rio Alto Exploration Ltd. last June. Gas from Rio Alto's properties averaged 376 mmcf/d in the second half of last year, helping offset other declines in the buyer's portfolio.

A better picture of what's happening in the Canadian market comes from looking at several producers that were not active buyers of entire companies or large properties.

EnCana cranked up its output 9.5 percent in the final quarter of 2002 versus the year-earlier period. Husky Energy Inc. was the only other producer to push up gas production over the same span, with its numbers rising 1.4 percent.

On the other side of the fence, Nexen Inc., Imperial, and Shell Canada Ltd. saw their daily volumes decline by between six and eight percent in the comparative quarters. Petro-Canada had a smaller slip, but its gas volumes still dropped 2.6 percent over the period.

As a group, these six companies saw their gas production drop an average of two percent between fourth quarter of 2002 and the last reporting period of 2001.

It's possible strong prices, which show little sign of weakening based on the forward strip for the next 12 months, will cause producers to pile into gas drilling projects like frat boys packing a Volkswagen Beetle during a beer run. Canadian Natural, for instance, expects to drill almost 600 gas wells this year after drilling about 160 in 2002. Petro-Canada, however, expects annual production this year will average 690 mmcf/d, down four percent from 2002's 722 mmcf/d.

Optimists point to deeper horizons, such as the Slave Point formation that yielded the prolific Ladyfern field in northeastern British Columbia (BC), as an example of the untapped potential of Western Canada, which is under-drilled compared with more developed gas basins in the U.S.

However, figures released this week by Canadian Natural as part of its fourth-quarter results may give optimists a reason to visit an optometrist to ensure they are seeing the whole picture.

Canadian Natural's share of the field declined to 127 mmcf/d in the final three months of last year from 178 mmcf/d in the third quarter. The number is now down to 80 mmcf/d, and the company expects the total will dwindle to 20 mmcf/d when December rolls around.

The firm said it received a 30 percent pre-tax return on its investment in Ladyfern, so it's not crying about the project's economics. However, the field's unexpectedly fast decline certainly raises questions about the sustainability of Canada's role as the supplier of about 16 percent of daily U.S. gas demand.

A recent study by consulting firm Purvin & Gertz, which examined more than one million gas wells in North America, said supplies will remain tight for a couple of years. The report concluded gas production in Alberta, home to 85 per cent of Canada's daily output, has peaked after rising for more than five decades.

BC, the East Coast, and the Arctic will add more supply over the longer term, but it's likely daily gas output in Canada will decline between two and four percent this year, following an estimated three percent dip in 2002. Last year's decline was the first time since 1986 that this country's daily gas numbers did not rise.

The decline by itself is not a huge deal. But this year's rapid depletion of storage inventories on both sides of the border is going to ensure it provides a larger-than-normal impact on the gas market.

Every 100 bcf decline in U.S. storage raises daily demand during the injection season (April through October) by roughly 500 mmcf/d. If the U.S. exits March with storage around 700 bcf, rather than the more usual one trillion, Canadian producers are not going to be able to step up and satisfy the extra demand of about 1.5 bcf/d.

The competition for gas could even heat up this summer if hot weather boosts air conditioning loads and strains already below-average water levels in hydroelectric reservoirs in the western half of the continent.

What does it all mean? More good times for gas producers and more wallet-emptying utility bills for consumers.

Associate Editor: Robin Beckwith