North America: Canada

NORTH AMERICA

Canada

Robert Curran, Calgary, Canada

At the outset of 2001, there was an air of unbridled optimism in downtown Calgary. Flush with cash, producers spoke of massive production increases and the occasional mega-project. Halfway through the year, sustained high oil and natural gas prices, record-shattering financial results and a bullish industry outlook have combined to exceed all expectations.

Despite a recent onslaught of price warnings and concerns about the sustainability of current activity, the first half of 2001 established several new standards, including drilling levels, overall profits, export throughput and revenue, and merger and acquisition activity. But the record numbers have not been reflected in stock prices, which continue to trade at levels lower than expected.

Canadian drillers may be on their way to setting yet another record for most wells drilled in a year. Operators drilled a record 18,480 wells last year, and the forecast calls for as many as 19,455 this year. (Photo by Steve Holmes, SW Holmes Oilfield Photography, Calgary)

Acquisitions and expenditures. The result has been a slew of takeovers and mergers, highlighted by Conoco Inc.’s C$9.8-billion takeover of Gulf Canada Resources Limited. The deal, which includes C$3.1 billion in debt, comes almost 20 years after Conoco substantially reduced its Canadian position by selling its majority stake in Hudson’s Bay Oil and Gas Co. Ltd. to Dome Petroleum.

The Conoco / Gulf deal came on the heels of a tremendous first quarter for Gulf, which was itself looking for potential takeover targets. Aside from gaining a significant land position and production in Western Canada, Conoco also gains a commanding position in Canada’s McKenzie Delta area, to the far north, a stake in the Syncrude oilsands plant in northeastern Alberta, and substantial holdings in southeast Asia. Conoco’s worldwide production will increase some 32% to 335 million bbl of oil equivalent (boe) this year, and reserves are expected to increase by 40%, to 3.7 billion boe.

The Gulf sale was the largest oil and gas transaction in the first half of 2001. According to Crosbie & Co., there were 74 deals worth C$18.2 billion through June. Some other big deals (all friendly) in 2001 include:

• Hunt Oil acquired Chieftain International for C$915 million in June.
• Talisman Energy took over Petromet Resources for just over C$800 million in April.
• PetroBank Energy and Ventus Energy announced a $300-million merger in early July. Petrobank also closed its $124-million takeover of Barrington Petroleum in April.
• Petrofund Corp., a royalty trust, purchased Magin Energy for $266 million in May.
• Pengrowth Energy Trust acquired Emera Inc.’s 8.4% stake in the Sable Offshore Energy Project, offshore Nova Scotia, for $265 million in June.
• Anadarko Petroleum purchased Gulfstream Resources Canada for $208 million in June.
• Ketch Energy acquired Post Energy for $200 million in June.

A couple of potential transactions that have been rumored involve two of Canada’s largest remaining domestic producers, Petro-Canada and PanCanadian Petroleum. Petro-Canada, which is still 18% owned by the Canadian federal government, has sparked some interest after the feds relaxed ownership rules for the former Crown corporation. The new rules will double the limit on individual share ownership to 20% and abolish the regulation that prohibits foreign ownership from exceeding 25%. Speculation continues that the government may consider selling its stake, which is valued at approximately $1.8 billion.

In PanCanadian’s case, the rumors have been fuelled by its parent company, Canadian Pacific, and its plans to spin PanCanadian off later in 2001.

The emerging trend, both in acquisitions and in expenditure plans, is the renewed long-term interest American companies have in developing Canadian opportunities. At a recent investment symposium in Calgary, four U.S. independents summarized their spending plans for Canada in 2001.

Apache Canada plans to spend C$560 million north of the 49th parallel this year, followed by Anadarko Canada (C$385 million), Burlington Resources Canada Energy (C$180 million), Devon Energy subsidiary Northstar Energy (C$165 million), and Canadian Forest Oil (C$105 million).

Meanwhile, Canadian producers upped their sales to the U.S. as high commodity prices, coupled with the perennially weak Canadian dollar, generated massive export revenues. In December 2000, for example, a record high of 362 Bcf of natural gas was shipped southward. Canada’s export capacity is currently more than 11 Bcf per day.

The surge in export volumes has also produced a massive increase in export revenues. In the first quarter of 2001, the value of Canadian gas exports to the U.S. were approximately US$7.2 billion (approximately C$11 billion), almost three times the amount collected in the first quarter of 2000.

On the crude side, Canada remains the third-largest supplier to the U.S., shipping about 14% of U.S. crude imports, or some 1.4 million bpd, in the first quarter of 2001.

The increased revenues have also translated into big money for the provincial governments, particularly in Alberta and British Columbia. Earlier this year, the Alberta government announced a budget surplus of about $5.5 billion, largely due to royalties collected from industry. In addition, Alberta’s economy will be sheltered from the economic downturn other provinces will experience this year, again due to the robust activity in the oil and gas industry. And in British Columbia, the oil and gas sector was the top producer of royalties for the first time ever, at $1.3 billion, bumping the forestry industry from its traditional top spot.

The upswing in industry and government fortunes has led not only to maximizing conventional oil and gas deposits, but has also sparked renewed interest in more capital-intensive developments, such as coalbed methane, production and upgrading schemes in Alberta’s massive oilsands deposits and tapping gas reserves of the far north.

Land sales. Bonus revenues from land sales are considered one of the key indicators of industry health and future activity. In the first half of 2001, revenue collected by western Canadian provincial authorities for land sales set a new record of $957.1 million, almost 50% higher than the $649.6 million taken in last year. Given that Alberta’s first land sale of the second half set a new single-sale all-time record of $125.5 million, it seems likely that the record of $1.51 billion, set in 1997, will fall in 2001.

Alberta again led the way through June, collecting $630.7 million, followed by British Columbia at $293 million, Saskatchewan at $32.4 million and Manitoba at $837,555. The average price per hectare in Alberta was $346, compared to $301 in the first half of 2000. In British Columbia, the average was $578 per hectare, versus $339 last year. The huge jump in B.C. land sales was a primary reason oilpatch revenues will continue as a key driver of the provincial economy.

Drilling. If the drilling pace last year was frantic, then few words are appropriate to describe current activity in the drilling and service sectors. Drilling is once again on a record pace, demand for drilling and service rigs has skyrocketed, and companies that do not have rigs under contract may not be able to spend the money they have allocated for their 2001 drilling programs.

Table: What 20 Canadian drillers plan for 2001

World Oil’s six-month survey of Canadian drillers indicates that industry’s focus continues to shift away from oil. This year, 65% of all wells drilled will target natural gas. This compares to 62% in last year’s survey and 59% in 1999.

Survey results indicate that activity will drop 5%, which is counter to current projections. However, last year’s survey also produced similar doubts, which were disproved later. Nonetheless, the survey shows Alberta and British Columbia activity will be down by 6% and 26%, respectively. On the other hand, Saskatchewan and Ontario should see drilling increase.

Through June of this year, there were 8,961 wells completed in Canada according to the Daily Oil Bulletin, of which 2,445 (27.3%) were oil wells, 5,450 (60.8%) were gas wells, and 1,066 were dry. Activity is 23.8% higher than the 2000 total of 7,238 wells drilled through the same period. At the current pace, drilling should surpass last year’s record of 18,480 wells. In addition, through June, the number of well licenses issued by western Canadian authorities reached 11,000, 9% higher than last year and a new six-month record.

Gas drilling has been the driver of the current increase in wells drilled. At this point last year, there were 3,670 gas wells, or just over 50%. The huge increases in gas prices of last winter and aggressive spending in 2001 have led to the 48.5% increase in gas drilling.

Adding to the pace has been a very dry winter, spring and summer, a shorter than normal spring break-up and a larger rig fleet. In response to the bullish outlook, the Canadian Association of Oilwell Drilling Contractors’ forecast of wells to be drilled in 2001 has been revised upward, to an unprecedented 19,455 wells. In October 2000, the association predicted a total of 18,542 wells drilled in 2001.

Rig utilization is expected to average 76% for the year, with an average of 488 rigs working out of the total fleet of 640. CAODC pegs the break-even point for average activity for drillers at 55% utilization.

Meanwhile, the Petroleum Services Association of Canada revised its forecast in April to 18,205 wells for the year, after originally projecting a total of 16,699 in early 2001. Of that total, 10,518, or 63%, will be gas wells, says PSAC. The service association’s forecast maintains its traditionally more bearish outlook than the CAODC.

The increase in the rig fleet again raises the concern of finding enough qualified workers to meet demand. With the local economy booming over the past two years, competition for workers is fierce. In response, training programs are operating at record levels, and companies are recruiting workers from far abroad.

Production. The prolonged surge in oil and gas prices experienced this year has resulted not only in increased production, but also renewed interest in capital-intensive mega-projects, in Alberta’s oilsands, East Coast offshore development and natural gas in the far north.

Total production of crude oil and equivalent, including bitumen, synthetic and natural gas liquids, was 2.83 million bpd through June, up slightly from 2000. Output of conventional light and medium crude fell 2.4% to 813,000 bpd, versus 833,000 bpd in 2000, and bitumen and heavy oil production increased 7.2% to 890,000 bpd, compared to 830,000 bpd last year.

Synthetic production is on track to post another record this year, with output from the Syncrude and Suncor mines near Fort McMurray, Alberta, at 350,000 bpd, up 7.7% from 325,000 bpd in 2000. Expansions to the Suncor and Syncrude operations, and projects proposed by Husky Energy, Koch, Shell Canada, Canadian Natural Resources, True North, PanCanadian and Petro-Canada, to name a few, are projected to increase oilsands production by 75%, to about 2.7 million bpd by 2010. Total spending on these projects is currently pegged at around C$28 billion.

Offshore production was 143,000 bpd in 2001, down slightly from 145,000 bpd in 2000. With production increases at Hibernia and a slate of new projects, East Coast output could surpass Western Canadian conventional light and medium production by 2010.

This year (to date), natural gas production increased to 17.7 Bcfd, up 1.9% over 2000. Coupled with oil exports, the value of hydrocarbons shipped out of Canada rose to C$55.9 billion in 2000, up a staggering 60.2% over the C$34.9 billion in 1999. Those levels are expected to increase slightly in 2001.

Offshore. Activity offshore continues at a steady pace on the East Coast, fueled by the growing infrastructure and better understanding of the area’s geology. At Hibernia, two wells were drilled in the first quarter of 2001, one in the Hibernia formation, the other in the Avalon formation. Nevertheless, production is expected to average about 170,000 bpd, after hitting 180,000 bpd last year.

The main oil pool at the White Rose field, just over 200 mi east of St. John’s, Newfoundland, is believed to hold probable oil reserves of 250 million bbl. Production is tentatively slated to begin in 2003, but the project has been dogged with controversy over operator Husky Oil’s decision to utilize a floating storage production and offloading (FPSO) vessel in the production stage rather than a gravity-based unit. Local politicians and businesses would prefer to see the gravity-based system, because it could be constructed locally. The group also says the system would allow gas reserves to be developed sooner. Regardless, Husky announced earlier this year that it was in the final tender phase for the topsides production facilities on the FPSO.

At Hebron, about 20 mi southeast of Hibernia, Chevron Canada Resources continues to evaluate the economics of the field, but still plans to submit a development application to the government by 2002. Hebron consists of three fields, is highly fractured and predominantly contains heavy oil, with reserves estimated to be anywhere from 400 million to 700 million bbl. Current plans could see first oil in late 2005 or early 2006.

Offshore Nova Scotia, PanCanadian continues to move toward development of its Deep Panuke gas discovery. The company has not finalized its choice for the offshore production facility, but plans to begin full production by 2005. To date, the four test wells drilled in the field have each produced over 50 MMcfgd. PanCanadian estimates Deep Panuke reserves at one Tcf.

As activity intensifies offshore, the two main beneficiaries, Newfoundland and Nova Scotia, have become embroiled in a turf war over the lucrative royalties that will be collected from future development. The area in question is the Laurentian sub-basin, located south of the Grand Banks. Reserves are estimated at 700 million bbl of oil and 9 Tcf of gas.

A Supreme Court tribunal – which could take up to a year to submit its final report – will hear arguments from both sides in November. In the meantime, more than $100 million worth of work commitments in the sub-basin could be delayed until the dispute is resolved.