CAPITAL: Ottawa
MONETARY UNIT: Dollar
REFINING CAPACITY: 1,911,650 b/cd
OIL PRODUCTION: 1,862,600 b/d
OIL RESERVES: 4.93 billion bbl
GAS RESERVES: 63.8 tcf
Canadian producers weathered the world oil price depression of 1998-99 and faced a positive future.
East Coast exploration and production remained strong, oil shale and heavy oil projects continued on course, and gas activity in Alberta took up much of the slack of the oil downturn.
The Petroleum Services Association of Canada (PSAC) predicted a strong drilling year in 2000, with emphasis on natural gas projects.
PSAC forecast 14,500 wells would be drilled in 2000, most in Alberta, compared with an estimated 10,200 wells in 1999. PSAC said its estimate was conservative and considered the possibility of a shortage of trained drilling personnel. It expected a 30% increase in drilling activity in Canada`s four western provinces during 2000. The Canadian Association of Oilwell Drilling Contractors forecast 14,331 wells would be drilled in 2000, based on an average utilization rate of 60% and a price of $18/bbl (US) for West Texas Intermediate crude. Canadian drilling peaked at 16,484 wells in 1997 and fell to 9,744 in 1998.
Fort Liard finds
Paramount Resources Ltd. and Berkley Petroleum Ltd., both of Calgary, had a significant gas discovery in the Fort Liard area of the Northwest Territories.
The well, just north of the British Columbia border, flowed on test at a rate of 45 MMcfd.
Paramount, Berkley, and partners planned more drilling and expected to begin commercial production in 2000. They had suspended three other wells in the area after achieving only marginal production.
Also, Chevron Canada Exploration Ltd. had a major discovery in the same area, which it said could produce at up to 100 MMcfd from reserves of up to 600 bcf. Meanwhile, Paramount and Berkley planned to build their own pipeline to mainline connections rather than, as in the past, asking TransCanada PipeLines Ltd. and Westcoast Energy Transmission Ltd. to build lateral connections to new fields. Paramount said it could not reach an acceptable deal with the two major pipelines.Paramount and Berkley were majority owners of Shiha Energy Transmission Ltd., which applied to the National Energy Board to build a 15-mile, 106 MMcfd pipeline from wells in the Fort Liard region.
The gas would be treated at a plant proposed by Paramount and shipped through a new 102-mile pipeline to connect near Fort Nelson, BC, with a mainline operated by Westcoast.
The project, including the $16.9 million Fort Liard line, would cost about $90 million. Paramount would operate both the new plant and pipelines.
Meanwhile, the Northwest Territories government and TransCanada agreed to work together to develop a gas transmission infrastructure in the southern Northwest Territories-and eventually in the Mackenzie Delta region-to exploit the burgeoning gas play there.
That followed a deal between Westcoast and the Acho Dene Koean aboriginal group to jointly develop a gas infrastructure in the Fort Liard area. Gas gathering, processing, transportation, and distribution were envisioned. TransCanada estimated southern Northwest Territories reserves at 1 tcf, with total potential for 3-5 tcf. TransCanada also was exploring a longer-term opportunity in the Mackenzie Delta, where reserves and potential were 10 tcf and 65 tcf, respectively Mackenzie Delta
Operators said development was in sight for huge gas reserves in the northernmost Mackenzie Delta region of the Northwest Territories, a quarter century after the gas was found.
Major gas finds in the Fort Liard area led some industry players to believe that Mackenzie Delta gas could flow south by 2005. Also, those finds would bring pipelines to southern markets closer to the Mackenzie Delta.
Four Calgary-based companies planned to spend $182.5 million on exploration and development of leases in the Mackenzie Delta region of Canada`s High Arctic.
Petro-Canada Ltd. and Anderson Exploration Ltd. planned to spend $105.2 million to explore two properties in the Mackenzie Delta area over 5 years, with Petro-Canada holding a 60% interest and Anderson 40%. The companies held leases covering 897,000 acres.
Petro-Canada would gather and analyze seismic data before drilling in 2001 or 2002.
Burlington Resources Ltd. planned to spend $78 million over 5 years exploring and developing two parcels. The tracts covered 360,000 acres and adjoined two onshore discoveries, Niglintgak and Taglu gas fields. The two fields had estimated reserves of 2.5 tcf of gas and 60 million bbl of crude oil and NGL.
The National Energy Board estimated 9 tcf of gas had been found in the region, with an upside potential for 64 tcf.
A study by consulting firm Purvin & Gertz said gas could flow from Canada`s arctic regions between 2007 and 2020, depending on economic factors.
It said a sustained price of $2.50/Mcf (US) would support the operating, gathering, processing, and transportation of gas from the region to the North American gas grid.
In 1988, the National Energy Board granted Gulf Canada Resources Ltd., Imperial Oil Ltd., and Shell Canada Ltd. licenses to export gas produced in the Mackenzie Delta, but they were never used. Those firms were expected to ask the government to extend the licenses when they expired in October 2000.
Heavy oil
PanCanadian Petroleum Ltd. and Gulf combined their heavy oil assets on the Alberta-Saskatchewan border in a $400 million joint venture.
The companies said merging operations on properties in the Lloydminster region would cut costs and share expertise while creating one of Canada`s biggest heavy oil producers.
The deal was seen as a sign of resurgence in the heavy oil business in Canada as a result of improving oil prices and narrowing differentials with light oil prices.
PanCanadian would own 52% of the venture and Gulf 48%. The operation would have about 100 million bbl in reserves of conventional heavy oil, production of about 34,450 b/d, and more than 1.4 million acres of undeveloped land.
PanCanadian would contribute heavy oil assets south, east, and northwest of Lloydminster. It would not include properties at Pelican and Christina Lake, Alta., or thermal properties at Senlac, Sask.
Gulf would contribute many of the heavy oil assets in the Lloydminster area it acquired in a 1997 takeover of Stampeder Exploration Ltd. but not oilsands holdings at Kerrobert, Sask., or Surmont, Alta.
Separately, Alberta Energy Ltd., Calgary, another major heavy oil company, was considering increasing primary heavy oil production at its Suffield and Pelican Lake, Alta., leases. It had applied to develop its Primrose properties to produce 10,000 b/d of heavy oil and was considering an increase to 15,000 b/d.
OILsands projects
Suncor Energy Inc. began construction of a $2 billion expansion of its oilsands operations in northern Alberta.
Suncor`s Project Millennium expansion would increase synthetic crude production to 220,000 b/d from 105,000 b/d, add a second production line and a sulfur recovery plant, and accelerate plans for a new Steepbank mine in the Athabasca area of Alberta. It was scheduled for completion in mid-2001.
Suncor signed a deal with TransAlta Corp., Calgary, to build and operate a $315 million cogeneration power plant for the oilsands project.
The company said it wanted to ensure it had a reliable and secure supply of electricity. The natural-gas-fired cogeneration plant would produce up to 360 Mw of electricity and 2 million lb/hr of steam. Power not used by Suncor would be sold through Alberta`s power grid.
Mobil Oil Canada Ltd., which later merged with Imperial, said it was delaying a construction start on a $2.5 billion oilsands project in the same region for 2 years to 2002.
Mobil said low oil prices and a decision to use cash elsewhere forced it to postpone its Kearl oilsands project in the Fort McMurray area of Alberta.
Mobil still planned to spend $1.2 billion to develop a mining site and an additional $1.3 billion for an upgrader to process bitumen into light syncrude.
Shell was seeking another partner in a $3.8 billion oilsands project in northern Alberta after Broken Hill Pty. Co. Ltd. (BHP) withdrew from a 25% interest in the Muskeg River mine project. BHP still would pay for 25% of a $180 million feasibility study.
Shell had received regulatory approval for a $1.4 billion oilsands mining operation. The project would also include a $1.9 billion heavy oil upgrader at Shell`s Scotford refinery, near Edmonton, and the $500 million Corridor pipeline connecting the mine and upgrader.
Shell had to begin production by 2003 under terms of its lease. The project would produce 150,000 b/d of syncrude as early as 2002 if it proceeded on schedule. The company estimated its potential oilsands reserves at more than 6 billion bbl.
Koch Canada Ltd. and UTS Energy said they remained committed to a drilling program and prefeasibility study for an oilsands project.
Koch said its Fort Hills oilsands project in northern Alberta could produce up to 90,000 b/d of bitumen and would not require a full-scale upgrader, given access to the company`s refinery at Pine Bend, Minn.
A final decision on the project would be made in early 2002. Koch had a 78% interest and UTS the remainder.
Sable Island
The National Energy Board reapproved the $1 billion gas pipeline system from Sable Island off Nova Scotia to New England.
The board initially approved the Maritimes & Northeast Pipeline system, but the Federal Court of Appeals ordered it to reopen the application because of an aboriginal group`s appeal.
NEB urged the pipeline and the First Nations aboriginal group in Nova Scotia to continue negotiations. The line had been completed and was ready for start-up.
The aboriginal groups were seeking compensation for the pipeline`s crossing their lands. Partners in the 460 MMcfd pipeline were Westcoast, Mobil, and Duke Energy Corp.
In the field, work was completed at the Thebaud, North Triumph, and Venture production platforms. A 122-mile, 26-in. pipeline was finished to shore.
Onshore, the Point Tupper fractionation and Goldboro gas plants were completed, as was an 8-in. gas liquids pipeline and a lateral gas line to Cape Breton Island.
SOEP would deliver gas to markets in Atlantic Canada and the US Northeast. Project interests were Mobil 50.8%, Shell 31.3%, Imperial 9%, Nova Scotia Resources Ltd. 8.4%, and Mosbacher Operating Ltd. 0.5%.
Nova Scotia sale
A Mobil-Imperial-Shell group dominated a 1999 lease sale off Nova Scotia.
They bid nearly a third of the total $592.5 million in work commitments offered for 19 of 20 exploration licenses covering about 2.2 million hectares.
The group bid a total of $189.9 million for six parcels (Nos. 3-8).
Offshore bidding was managed by the Canada-Nova Scotia Offshore Petroleum Board.
The largest bid for a license was $93.3 million, submitted by PanCanadian, Marathon Canada Ltd., Murphy Oil Co. Ltd., and Norsk Hydro Canada Oil & Gas for Parcel 11.
Overall, Imperial alone bid nearly $138 million, including about $100 million for Parcels 12 and 13. Shell Canada bid nearly $107 million and Mobil more than $86.6 million.
Parcels 16-20, in 2,500-4,000 m of water, drew bids. They were the deepest exploration tracts to draw industry interest to that date off Nova Scotia.
Off Newfoundland, the Hibernia and Terra Nova field management groups agreed in principle to increase their cooperation in the Jeanne d`Arc basin on the Grand Banks.
The companies already shared some services and had said they planned further cooperation to cut costs. The Hibernia Management & Development Co. was owned by lead partner Mobil, Chevron, Petro-Canada, Murphy, Norsk Hydro, and the federal government. Terra Nova, under development, was owned by lead partner Petro-Canada, Mobil, Norsk Hydro, Murphy, Chevron, Husky, and Mosbacher.
Pipeline tolls
TransCanada and the Canadian Association of Petroleum Producers (CAPP) signed a memorandum of understanding that outlined a new pricing structure for gas transportation on the Nova Gas Transmission system. The policy, to be phased in over 4 years, would be more "receipt-point-specific" with "pricing more reflective of the relative distance and diameter of pipe from each receipt point," said CAPP and Nova.
The policy, subject to regulatory approval, would create a more competitive pricing environment and greater customer choice, said TransCanada Pres. and Chief Executive Officer George Watson. CAPP represented large and medium-sized companies. But the region`s small producers rejected the accord.
The Small Explorers & Producers Association of Canada (Sepac) objected to provisions requiring companies to build their own lateral line connections to the mainline.
The new toll structure linked rates to service costs and replaced a postage stamp toll system in Alberta, where producers paid the same toll rate regardless of gas location.
Sepac said its members do not have cash to build their own laterals, noting that operators were having to move farther from mainlines in northern Alberta to find gas and that some already had cash flow problems.
TransCanada said the industry was moving into a more competitive environment and there were enough companies to compete to build the smaller lines required.
Alberta rules
The Alberta government was planning to change its royalty tax credit program for producers beginning Jan. 1, 2001.
The program gave producers a credit of 25-75% on the first $2 million in royalties paid. It had been in place since 1974 and was costing the government about $256 million/year.
CAPP warned against possible changes to the incentive program and called for negotiations with industry.
The Small Explorers & Producers Association of Canada also advised against changes that would hurt the industry.
Alberta Treasurer Stockwell Day said the government did not intend to scrap the program but to make it "more efficient" for small and medium-sized companies. Also, Alberta was being urged to change its regulations regarding natural gas flaring. The Citizens` Oil & Gas Council (COGC) urged the government to tighten its regulations on flaring at old and new wells and plants and eliminate grandfathering provisions exempting existing sites from meeting higher standards.
CAPP said a near-ban on gas flaring would be uneconomic and impractical. It said the industry had cut flaring volumes 13%. The Alberta Energy and Utilities Board had proposed a 15% cut in flaring by the end of 2000 and an additional 10% by 2001. COGC said that did not go far enough. And Alberta was considering a multilevel royalty program for gas that would ensure adequate feedstock for its expanding petrochemical industry.
Petrochemical firms had complained that new export pipelines were moving both gas and NGLs to the US market, preventing substantial plant investments in Alberta.
One government option was to take gas royalties in kind.
Companies
Talisman Energy Inc. agreed to acquire Rigel Energy Corp. in a $1.2 billion deal. Both were Calgary firms.
Talisman said the deal made it a dominant player in Canada`s Peace River Arch and Alberta foothills plays, pushing the combined firms` production of gas in Canada to 850 MMcfd in 2000.
In the North Sea, the combined company owned about 54% of the 50-70 million bbl Blake oil field development. Also, Talisman added 8,500 b/d of production to its core central North Sea area, as well as a number of high-potential exploration prospects near Beatrice and Buchan fields, which the company operated.
With the acquisition, Talisman`s production grew to about 340,000 boe/d in 2000 from 246,000 boe/d, with more than 1.1 bcfd of gas sales worldwide.
Also in 2000, Houston-based Burlington Resources Inc. paid $2.5 billion in a friendly takeover of Calgary gas producer Poco Petroleums Ltd.
The merger created North America`s fourth largest gas producer and gave Burlington entry into Canada, where it previously had no leases or production.
Petro-Canada and Suncor ended merger discussions. Both were integrated companies with extensive upstream and downstream operations. Suncor also operated a major oilsands project in northern Alberta that was being expanded.
Canada`s federal Competition Bureau approved the merger of the Canadian units of Exxon Corp. and Mobil Corp., saying it would not substantially lessen competition in Canada. Imperial, owned 70% by Exxon Corp., merged with Mobil Oil Canada, pooling assets of about $22 billion. Mobil Canada was a major natural gas producer with significant interests in East Coast offshore oil and gas developments such as Hibernia, Terra Nova, and the Sable Offshore Energy Project. Imperial was Canada`s largest oil and gas producer and refiner, holding significant interests in oilsands and heavy oil operations in Alberta.
TransCanada was returning to its core business by selling all assets outside its $21 billion pipelining, power generation, and marketing activities in Canada and the northern US.
CEO Doug Baldwin said Trans-Canada`s strength was its low-cost gas transmission from gas fields in Western Canada to large energy markets in North America.
TransCanada planned to sell an extensive list of pipeline and related assets, many of which were acquired in a merger with Nova Corp. They included oil and gas pipelines, electric generating plants, and related facilities in place or under development in a dozen nations.
Baldwin said the sales would raise an estimated $3 billion, which would be used to repay debt.
In addition to exiting the international and midstream businesses, TransCanada planned to sell the Express Pipeline System, including the transmission and marketing of crude oil and refined products, and Cancarb Ltd., a carbon black plant in Alberta.
The company had cut staff to 4,400 from 5,000 since the Nova merger and sold about $1 billion of assets as part of its retrenchment.
That included the sale of Angus Chemical Co.; shifting its investment in the Northern Border Pipeline system into TC Pipelines LP and then offering it for sale; and an deal to sell its US midstream facilities and US NGL, marketing, and trading businesses to Coastal Corp., Houston.
Petro-Canada planned a "staged exit" from conventional crude oil production in Western Canada to concentrate on natural gas, oilsands, and offshore oil projects.
The company planned to sell conventional oil assets and acquire gas properties, while participating in oilsands projects and offshore developments such as Terra Nova, off Newfoundland.
