Oil, Gas Drilling Rewards Shrinking in Alberta

Abstract: A report from Alberta's major energy regulator contains good news for drillers, but it also shows the rewards for oil and gas wells will continue to shrink over the upcoming decade.

Analysis: Recent decisions by Canadian producers Baytex Energy, Crescent Point Energy, and Bonavista Petroleum to create income trusts aren't a huge surprise, but a new report from Alberta's energy regulator sheds some light on why so many executives are curtailing exploration and focusing more attention on other means of generating cash.

Despite concern by analysts that the field is becoming overcrowded, the stampede of producers into income trusts does not appear to be slowing down. Tax advantages owned by trusts, since investors absorb taxes, combined with retail popularity have created something akin to a gravitational pull that has tugged in dozens of petroleum companies over the past three years.

The willingness of investors to pay almost double, based on barrel of oil equivalent production, for income trusts has convinced many exploration and production executives that it's time to join in the rush towards income trusts.

The favor of stock markets is only part of the equation. Another factor is contained in an analysis released recently by Alberta's Energy and Utilities Board (EUB).

The board's staff members reviewed production and drilling results for last year--pretty standard stuff. They also provided some estimates about the future of oil and natural gas production in the province, home to the bulk of the oil and gas exported to the United States. The forecast for the upcoming decade, unless you're a major Alberta E&P firm with billions of dollars to spend on oilsands projects, is somewhat discouraging for conventional oil and gas players.

Remaining reserves of conventional oil in Alberta are pegged at 1.6 billion barrels, compared with 174 billion barrels for bitumen, a tar-like heavy oil extracted from the province's massive oilsands deposits.

Drilling and enhanced oil recovery projects replaced only 41 percent of conventional oil production in 2002. One reason for the decline is the shrinking size of the prize. Initial production from new oil wells now averages about 33 barrels per day (b/d) in Alberta, compared with 51 b/d in the mid-1990s.

One cause of the shrinkage is the rapid climb in the number of producing oil wells in the province. Alberta had 34,600 producing oil wells last year, compared with 26,400 in 1992. About half--some 17,700 wells--pumped an average of 6.5 b/d last year, demonstrating the marginal rewards of many oil prospects in the mature Western Canadian Sedimentary Basin.

The numbers on the gas side were a little brighter but not enough to offset gloomy trends. (An important caveat is that the EUB's figures do not include any production or reserves for coalbed methane [CBM] since not enough data exists to draw firm conclusions. The Canadian Association of Petroleum Producers this week estimated that reserves of 75 trillion cubic feet [tcf] could come from CBM.)

New reserves from drilling replaced production in Alberta for the first time since 1982. Total output, however, declined 3.8 percent last year over 2001, to 4.8 tcf.

High prices are forecasted to push up production by 1.5 percent to 4.9 tcf in 2003, but the increasing maturity of the basin is expected to pare output by two percent annually to 2012. The province's total volume in that year is projected to have declined to 4.3 tcf.

Initial production from most Alberta gas wells is expected to drop to 282,000 cubic feet per day by 2012, down 20 percent from today's rate of approximately 350,000.

Board staffers calculated a separate decline rate for the southeastern corner of the province, a hot region for shallow gas drilling during the past five years. They predict a 40 percent decline in initial production in wells from the area over the next 10 years.

The report indicates Alberta will still have a healthy energy industry that plays an important role in North American supply over the next decade. But the EUB's figures show Canadian E&P executives face long odds when it comes to growing production.

The challenging exploration environment helps explains the exodus of Canadian players, large and small, to less developed basins in countries such as India, Colombia, Malaysia, and Kazakhstan. The potential for discoveries of much larger reserves helps mitigate political and economic risks, exemplified by Nexen's success in Yemen.

Since investors are willing to pay top dollar for income trusts that often don't show rising volumes on a quarterly basis, it's no wonder the parade of these Canadian trusts is starting to resemble the major streets of Pasadena on Rose Bowl day.

The news out of the EUB's analysis wasn't all bad. Service firms, for example, should be quite pleased with the drilling forecasts.

The regulator expects 2,000 oil wells to be drilled this year, 2,100 in 2004, and 2,200 per year until 2012. About 1,650 successful oil wells were drilled in 2002. On the gas side, the study predicts between 9,500 and 11,000 holes will be punched down annually until 2006, with activity in the following years averaging 10,000 wells annually over the remainder of the forecast period. Close to 8,100 gas wells were recorded in 2001.

"New pools are smaller and new wells drilled today are exhibiting lower initial production rates and steeper decline rates," the report says. "Factoring this in, the EUB believes that new wells drilled will not be able to sustain production levels over most of the forecast period."

The EUB document, available as a pdf file at http://www.eub.gov.ab.ca/bbs/products/STs/st98-2003.pdf, contains encouraging news for U.S. gasoline makers.

Production of Alberta's bitumen, which averaged 829,000 b/d in 2002, could triple by 2012. The huge increase favors Midwest U.S. refiners, particularly if Petro-Canada decides to abandon or scale back an ambitious refinery conversion because of rising costs (see Oil and Gas Advisory, May 3). Refiners in Illinois, Minnesota, and other states that can take the heavy slate should enjoy bigger margins as a glut forces Canadian suppliers to accept lower prices.

The EUB's forecast should also encourage companies with plans to import liquefied natural gas into the United States. The plants and ships are tremendously expensive, but it appears clear that the U.S. should no longer depend so heavily on Canadian gas, and further diversify its supply base.


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