Aeco natural gas prices

Beset by a flagging economy and sluggish demand, the Canadian upstream industry recognizes that the long-term fundamentals are still robust, particularly for natural gas. The trick will be to tread carefully during first-half 2002

As bullish as the outlook was at the outset of 2001, it is equally bearish for the year ahead. Last year we were all reminded of the vulnerability and frailty of not just ourselves, but of the markets and businesses we work in. Those in the industry have been reminded once more of the volatile nature of the oil and gas trade.

OVERVIEW

In 12 short months, the industry's mindset has been transformed from optimism and confidence to cautiousness and doubt. Despite coming off the best drilling year, ever, in Canada, the downward spiral of second-half 2001 has cast a pall over the industry.

Spending plans are down, profits are receding, and takeover rumors continue to swirl around the few remaining Canadian firms that managed to escape the past year unscathed. Oil and gas prices are substantially lower than they were at this point last year, when natural gas topped C$11.00/Mcf and oil flirted with US$30/bbl, WTI. This January, gas is about C$3.50/Mcf, and oil is hovering around US$20/bbl.

Last month, the Canadian arm of British Petroleum Plc announced plans to lay off as much as 20% of its 250-member, Canadian natural gas unit staff and 5% of its field personnel. If prices remain soft, other job reduction announcements are expected, according to industry observers.

The unexpected, rapid decline in commodity prices also led to lower-than-expected, third-quarter cash flow last year. In turn, this meant Canadian producers spent C$8.5 billion from July to September, compared to cash flow of C$5.7 billion, according to the Daily Oil Bulletin.

Even so, nine-month results were impressive, with producers recording net earnings of C$9.7 billion, compared to C$6.8 billion through the same period of 2000. But the second-half slowdown has put a damper on expected fourth-quarter earnings, and the stock markets have seemingly turned their collective back on most energy stocks.

A drop in stock prices, combined with the chronic weakness of the Canadian dollar, has traditionally put most publicly traded domestic producers at risk to be taken over, particularly when the industry fundamentals are otherwise fairly strong. In 2001, those factors came together and produced a number of deals worth more than C$40 billion. Of that total, American firms spent almost $37 billion.

The biggest deal of the year was Duke Energy Corp.'s pick-up of West-coast Energy Inc. for C$12.1 billion in September. Next largest deals were Conoco Ltd.'s C$8.9-billion takeover of Gulf Canada Resources Ltd. in May, and Devon Energy Corp.'s C$7.1-billion acquisition of Anderson Exploration Ltd. in September.

Other notable takeovers in 2001 include:

* Canadian Hunter Exploration Ltd., absorbed by Burlington Resources Inc. for $3.4 billion last October

* Encal Energy Ltd., bought by Calpine Corp. for $1.8 billion in February 2001

* Berkley Petroleum Ltd., acquired by Anadarko Petroleum Corp. for $1.5 billion in February 2001

* Chieftain International Inc., swallowed by Hunt Oil Co. for $891 million last June.

There were a number of companies that generated considerable takeover talk and speculation, but no deals. These included Petro-Canada, in which the federal government was rumored to be interested in selling its 18 % stake, and Talisman Energy Inc., which was reportedly set to divest its controversial assets in Sudan. In addition, just before press time, PanCanadian Petroleum and Alberta Energy confirmed rumors that they were in merger talks.

As is the norm, there were also some American companies that reduced their Canadian portfolios. KeySpan Corp. announced plans to sell non-core assets, including an unloading of its Canadian natural gas processing division sometime this year. USX Marathon Group sold a number of heavy oil properties in Alberta and Saskatchewan--to better focus on its Canadian natural gas assets--and incurred a one-time, C$126-million after-tax loss related to the sale. Anadarko also booked a US$464-million, after-tax ceiling-test write-down of its Canadian assets, due to lower natural gas prices and very high, heavy oil differentials at the end of the third quarter.

Perhaps reflecting the uncertainty of the times, industry analysts are reticent to commit too fully to any forecast of activity this year, although most seem to agree that the outlook will improve as time passes, not worsen. Yet, all of the cautiousness and uncertainty are belied by the astounding number of wells drilled in 2001, and the forecasts for activity this year.

According to the Daily Oil Bulletin, there were 17,983 wells drilled last year in Canada. This is a new record, and it's almost 9% higher than the 16,507 wells drilled in 2000. The majority of the drilling in 2001 targeted gas, with 11,200 gas wells drilled (62.3%). There were 4,702 oil wells (26.1%) and 1,768 dry holes (9.8%). In 2000, there were 8,929 gas wells and 7,578 oil wells.

The industry's volatility is amplified in the drilling and service sector, where companies were scrambling to find workers at the outset of 2001, but by December were facing some harsh balance sheet realities. Even so, the Canadian Association of Oilwell Drilling Contractors forecasts a 20% decline in drilling activity during 2002, to 13,600 wells. If achieved, this level would still be the fourth-best drilling year on record. CAODC based its forecast on an average WTI price of US$21/bbl, and average spot natural gas price of C$3.40/Mcf at Alberta's AECO-C hub.

The Petroleum Services Association of Canada (PSAC) has forecast a similar drop-off in activity, projecting 14,396 wells will be drilled this year. PSAC notes that this total is still above the 10-year average of 11,330 wells drilled. Last, but not least, the Canadian Association of Petroleum Producers is forecasting 15,000 wells for 2002, versus a tally of 18,017 wells in 2001.

In late 2001 and early 2002, World Oil conducted its annual survey of Canadian producers. The sentiment was slightly optimistic, with producers indicating they would drill 2,971 wells in 2002, down about 15% from 2001 levels. This compares with the consensus industry viewpoint, which calls for a 20% decline in drilling. In the past, World Oil's survey numbers have usually demonstrated a more bullish outlook than other samples and forecasts, and this year's sample group is no exception.

Gas drilling is expected to comprise 60% of the total. The survey also shows that exploratory drilling will actually increase, with about 23% of the wells expected to be wildcats and/or appraisals. Activity is expected to drop 13% in Alberta, fall 16% in British Columbia and decrease about 27% in Saskatchewan.

Despite the bearish forecasts, capital-intensive projects in Alberta's oil sands and offshore East Coast continue to draw tremendous interest for their long-term potential. Ironically, it is because of the mature state of the Western Canadian Sedimentary basin that most producers have turned to other areas. Even the far north is being considered seriously for large-scale development, given the massive gas reserves in areas like the McKenzie Delta.

The upsurge has been led by expansions at the two massive oil sands operations north of Fort McMurray, run by Suncor Energy Inc. and Syncrude Canada Ltd.

With the Millennium Project now onstream, Suncor announced plans for its next expansion, which will increase its output to 550,000 bopd by 2012. The Voyageur project is a combination of in situ, steam-assisted gravity drainage (SAGD) and open-pit mining. The company also secured regulatory approval for its C$1-billion Firebag in situ project, located about 25 mi northeast of its existing plant. The Firebag deposit is estimated to contain 9.6 billion bbl of recoverable bitumen.

Syncrude has been equally busy, proposing a $2-billion, capital expenditures budget for 2002. Of this, $1.75 billion has been ticketed for engineering, procurement and construction of the company's $4-billion, Syncrude 21 Stage 3 expansion, which includes enhancing the upgrader and adding a second train to the Aurora mine.

Petro-Canada has also entered the fray with announced plans to spend almost $6 billion on developing an integrated oil sands business. The company intends to enhance its refinery near Edmonton and construct an in situ plant at Meadow Creek, about 30 mi south of Fort McMurray. Meanwhile, Shell Canada Limited's $5.1-billion, 155,000 bpd Athabasca project is scheduled to be onstream later this year.