CANADIAN OUTLOOK

Wary oil patch limps into 2002

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

Robert Curran, Calgary

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.

What 25 Canadian drillers plan for 2002

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 Westcoast 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.

To the east, offshore activity is going strong, with Hibernia still producing and the Terra Nova project scheduled to begin production at the end of 2001. Between the two projects, there are projected to be 1.1 billion bbl of recoverable oil. At the Sable Offshore Energy Project, a decision is pending on whether the second phase will begin earlier than originally planned. The project produced an average 550 MMcfd in October, well above the 510 MMcfd originally expected.

Drilling/Land Sales

Given the current state of commodity prices and investor confidence, it would appear that the industry has every reason to be concerned about 2002. However, even though that pessimism first arose last year, producers went on to post a record year for drilling.

According to the Daily Oil Bulletin, the 17,983 wells drilled last year easily established a new record, which was previously 16,484 in 1997 (Editor’s note: Depending on the sources consulted, there is some dispute as to which of the last several years is the actual record-holder. Well counts for these years vary from source to source.). But at that time, the drilling fleet only totaled 509 rigs, and utilization was 82%. The total fleet rose to 655 rigs in the fourth quarter last year, for a utilization rate of 55%. Over the course of the year, an average of 637 rigs was available. However, only 398 were working, resulting in 63% utilization. Once again, the record number of wells drilled did not translate into record utilization levels, as the fleet continues to grow.

For 2002, CAODC projects a 20% decrease from 2001’s drilling level, to 13,600 wells. At the same time, the fleet is forecast to average 640 rigs in 2002, resulting in an average utilization of only 45%.

Another indicator of industry activity is government land sale bonuses. In 2001, spending set a new record at C$1.58 billion for 5.18 million hectares, or $305 per hectare, according to DOB records. The total was slightly higher than the previous $1.5-billion record, set in 1997. Last year’s total was 10% higher than in 2000, when land sales were $1.44 billion for 4.8 million hectares ($299/ha).

In Alberta, $1.08 billion was collected for 3.9 million hectares ($278/ha), versus $1.14 billion for 3.8 million hectares ($298/ha) in 2000. British Columbia set a new record, raising $439 million for 854,000 ha ($514/ha), more than 40% higher than the $248 million on 693,000 ha ($358.26/ha) raised in 2000. Saskatchewan’s results were slightly improved, with $56.2 million collected on sales of 372,525 ha ($151/ha), compared to $48 million for 283,200 ha ($170.69/ha) last year.

Production

As much as rising oil and gas prices bolstered activity in 2000, declining prices put a damper on production growth in second-half 2001. However, the real impact will be seen in 2002, as severely curtailed capital spending will likely generate lower production levels for the year.

Crude oil and equivalent production increased 1.6% in 2001, to 2.22 million bpd, versus 2.18 million bpd in 2000. Conventional light and medium crude output fell 4.1%, to 800,000 bpd from 833,000 bpd. However, bitumen and heavy oil production increased 6.5%, to 884,000 bpd from 830,000 bpd.

Synthetic oil production rose 3.7% to 337,000 bpd, compared to 325,000 bpd in 2000. Both Syncrude and Suncor are projecting higher output for 2002. Syncrude expects to reach production of 235,000 to 245,000 bopd this year, while Suncor targets productive capacity of 225,000 bpd.

On the natural gas side, production rose 3.5%, to 18 Bcfd from 17.37 Bcfd in 2000. Alberta’s output fell 1.4%, to 13.93 Bcfd from 14.13 Bcfd. However, British Columbian production jumped 19.8%, to 2.6 Bcfd from 2.17 Bcfd. In Saskatchewan, output fell 4.8%, to 650 MMcfd from 683 MMcfd.

Due once again primarily to the Sable Offshore Project, the largest percentage increase was for natural gas production for the remainder of Canada. This output rose 52.8%, to 820 MMcfd, from 387 MMcfd in 2000.

Offshore

The Hibernia development continued to produce the vast majority of East Coast oil, averaging approximately 140,000 bpd in 2001, about the same as the year before. The project now has 14 producing wells (with a 15th well currently being drilled), six water injectors and five gas injectors.

At Terra Nova, the first well was successfully completed in the field’s Far East fault block during November 2001. Project operator Petro-Canada said the well was not sufficient in itself to determine Far East reserves, but previous pre-drill estimates put the potential at 100 million bbl. This is on top of the 370 million bbl already identified in the field’s Graben and East Flank sections. As late as Dec. 20, Petro-Canada was targeting a year-end 2001 start-up at the project’s main reservoir.

The $2.3-billion White Rose project was approved by federal and provincial authorities last year. Just like Terra Nova, it will also employ an FPSO. Project partners Husky Energy Inc. and Petro-Canada are reviewing the conditions placed on the approval by the regulators. During first-quarter 2002, the partners will decide whether to proceed with the project.

The field contains an estimated 230 million bbl of oil and 2.1 Tcf of natural gas. If the partners decide to proceed, then production would begin in late 2004.

Other projects still in the works include Hebron-Ben Nevis, led by Chevron Canada, and the development of the Flemish Pass, northeast of Hibernia, and Salar basin, to the southeast. Petro-Canada holds a position in both of these areas.

On the other side of the country, a report commissioned by British Columbia suggests that West Coast offshore reserves could be tapped by state-of-the-art technology, although the high cost of employing the necessary equipment could render some projects uneconomic.

The province will review the report and submit its own findings early this year. There has been a government-imposed moratorium on West Coast offshore drilling since the 1970s.

Mr. Curran is a Calgary-based freelance writer.