The Alberta Energy Resources Conservation Board made it official last week, confirming independent reports that the province, the mainstay of Canadian natural gas, has passed a historic turning point, with aging fields past their prime entering a long-range decline. At the same time the province moved to shut in some gas production to protect its oil potential.

But Alberta, source of about four-fifths of Canadian supplies, does not have to experience the steep drop-off seen in the U.S. production area, the Alberta Energy and Utilities Board (AEUB) said in its annual state-of-the industry report. Gas producers collectively can improve the overall supply outlook by changing their behavior. It is not inevitable that Alberta gas production will repeat a pattern of rapid initial declines that Texas and Louisiana experienced after passing their peaks in the late 1960s and early ’70s, the report said.

In Alberta, the resource endowment is still robust enough for the deregulated industry to stave off fast drops in productivity. It can change its operating pattern, which the NEB has dubbed “just-in-time gas,” to keep itself alive by redirecting drilling to less exploited, deeper, bigger and costlier targets.

Much of Alberta’s development since deregulation has centered on shallow gas in southeastern Alberta, which contains over half of the province’s producing gas wells, but only 16% of 2002 production. Over time as supply depletion and tight markets sustain encouraging prices, the board “anticipates that the focus of exploration activity will shift to the western portion of the province (along the foothills of the Rocky Mountains) and correspondingly higher-productivity wells.”

And, there is the potential for coalbed methane. The board reported its field operations licensing records confirm that coalbed methane extraction is emerging as a new industry priority in Alberta, but it is still too early even to attempt to estimate reserves and productive potential in a field that remains in experimental and pilot plant stages, often cloaked with corporate confidentiality.

The more optimistic outlook tempered the bad news that for the first time since the 1986 onset of Canadian deregulation and the open “continental” market with the United States, production failed to grow last year. Alberta gas output fell by 3.8% to about 13.2 Bcf/d in 2002, the AEUB said in its annual report. The agency predicted an average annual decline of 2% through 2012.

The long-range erosion is forecast to develop after a brief respite this year, thanks to a drilling rush ignited by high prices in the last heating season. Alberta gas supply is projected to recover 40% of the ground lost in 2002 by a 1.5% increase in production owed to the flurry of field activity. It replaced 105% of 2002 production, keeping the province’s established reserves at 42 Tcf.

Echoing the National Energy Board (NEB), the AEUB attributes the emerging productivity decline partly to an operating pattern in the deregulated industry of relying on low-cost drilling for shallow reserves and quick financial returns — but primarily to natural aging of gas fields after a half-century of steady growth in output.

Reserves and productivity remain closely-watched, sensitive issues in Canada with implications for the gas trade with the United States. The agencies continue to have mandates to ensure that only gas deemed surplus to domestic requirements can be exported — in the NEB’s case to the U.S., and in Alberta’s case to markets anywhere beyond its boundaries including other parts of Canada.

The protective responsibilities date back to the births of the agencies and were not repealed by federal-provincial deregulation agreements, although methods of carrying out the mandates were overhauled. No demand for repeal emerged among Canadian producers or marketers as exports multiplied five-fold to 3.7 Tcf per year — 60% of the nation’s production — by taking a 15% share of the U.S. market. Until signs that productivity is over the hill developed over the past 18 months, the expansionist period included consensus forecasts of steady growth. The NEB is expected to join its provincial counterpart in setting aside the old consensus in a 25-year forecast of national supply and demand scheduled for release later this spring.

The AEUB stressed that it sees no reason to stop endorsing gas-removal permits on its 10-year forecast horizon. The agency predicted that by 2012 demand within Alberta for its own gas will still only be 39% of production.

Competition for supplies and sustained upward pressure on prices are expected to develop, however — and the oil industry will be among the biggest drivers as a result of another turning point reached by Canadian producers. At the same time as gas fields enter decline, conventional oil wells are depleting. They are being replaced by mining complexes and “in-situ” or underground extraction projects tapping the northern Alberta oil sands, where the AEUB estimates reserves within technical reach at about 315 billion barrels.

Both oil-sands methods are heavy users of gas for power generation and heat processes. The AEUB forecasts gas demand for oil sands production will about triple to 1.2 Bcf/d by 2012. Total Alberta gas consumption is projected to rise 32% to 4.5 Bcf daily.

The oil-sands development wave is also making access to gas reserves increasingly difficult in the northeastern Alberta region involved. Shallow gas production has been found to conflict with oil-sands extraction from deeper formations by reducing pressures in geological reservoirs. Since the oil-sands projects are larger and have longer lives, gas has to give way under provincial policy of maximizing the value of Alberta resources and government royalty revenues.

After six years of technical consultations and hearings, the AEUB last week announced a plan to make 11 gas producers shut in about 900 wells currently delivering 245 MMcf/d from an estimated 1 Tcf of reserves in the oil-sands region (see related story). The announcement for the shut-ins to begin in August, triggered a flurry of activity on stock exchanges, a split in the Canadian industry, and regulatory and potentially court-room duels. After it thoroughly studies the situation, the AEUB said as much as 50% of the shut-in gas could be returned to production.

Tight gas markets are also forecast to encourage oil-sands producers to work on technical improvements that include lowering the temperatures of their gas-fired processes and a new method of substituting hydrogen stripped out of the ore.

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