Eastern Canada Report

Offshore Eastern Canada has been long recognized as one of the world's most hydrocarbon-rich areas, but low oil and gas prices have discouraged investors from attempting to harvest product from the icy depths of the North Atlantic and the Gulf of St. Lawrence. During the last decade however, a steady decline in new fuel sources and skyrocketing prices have prompted companies to take a closer look at these difficult areas. The result has been a burgeoning oil and gas industry that can't move fast enough to suit an area plagued with economic hard times.

Quebec, Prince Edward Island, New Brunswick, Nova Scotia and Newfoundland are all in a hydrocarbon "hot spot", but the vast majority of activity is taking place offshore Newfoundland and Nova Scotia. In addition to the well-established Sable and Hibernia projects, several new offshore initiatives are in the early stages. A trend toward onshore exploration is also developing, with production expected to begin as early as this fall.

OFFSHORE

HIBERNIA

When Newfoundland's Hibernia oil field began producing in November of 1997, it was Canada's first major offshore oil project to start in a decade. The project's first well broke Canadian records.

It's success was soon heralded when, in Feb. of 1999 Hibernia increased oil production to more than 100,000 barrels a day following the start-up of a new gas injection well. Production had been restricted to an average of 68,000 barrels per day because of flaring constraints imposed by the Canada-Newfoundland Offshore Petroleum Board. Now, less than four years later, peak production rates reach180,000 barrels a day.

Hibernia is located in a water depth of about 80 metres (262 feet), in the Jeanne d'Arc Basin, 315 kilometres (195 miles) east of St. John's, Newfoundland. The two main reservoirs are Hibernia, located at an average depth of 3700 metres (12,136 feet) and Ben Nevis-Avalon, located at 2400 metres (7872 feet).

Hibernia oil is a light sweet crude with a density of about 32° to 34° API and a sulfur content by weight of 0.4% to 0.6%. The field contains approximately three billion barrels of oil in place, with recoverable reserves estimated to be 615M bbl.

Oil is stored sub-sea, in the Hibernia Gravity Base Structure (GBS). The crude-oil is then shipped via double-hulled tankers directly to market, or to Whiffen Head, Newfoundland, where it is shipped by additional tankers to both US and Canadian customers.

The enhanced Gorilla-Class rig, called Hibernia, was specifically designed for the harsh environment in which it manages simultaneous drilling and production operations. It is recognized as one of the most technologically-advanced mobile platforms in the world. The concrete production platform has a 15 metres (49 feet) thick ice belt, and a 1.4 metres (4.6 feet) thick icewall, equipped with 16 concrete teeth and a system of support-walls able to withstand a collision with a 1-million tonne iceberg. There are more than 30 GBS platforms operating in the North Sea, but none are designed to resist the impact of sea ice and icebergs.

Hibernia is owned by Mobil (33.125%); Chevron Canada Resources (26.875%); Petro-Canada (20%); Canada Hibernia Holding Corporation (8.5%); Murphy Oil (6.5%) and Norsk Hydro
(5%).

TERRA NOVA

Canada's soon-to-be second major oil field development is the Terra Nova project, located 350 kilometres (254 miles) east-southeast of St. John's, Newfoundland and southeast of Hibernia. The Terra Nova Floating Production, Storage and Offloading (FPSO) facility is currently in Bull Arm, Newfoundland undergoing hook-up and commissioning. Terra Nova is set to begin production late this year.

Like Hibernia, the Terra Nova project has to be specially designed to withstand the harshest of weather conditions, including an average Wind Speed of 35 kilometres (22 miles) per hour; Water Temperatures ranging from 1.7 to 15.4 Degrees Celsius (35- 60 Fahrenheit); seasonal fog, sea ice and icebergs.

Terra Nova has an estimated 370 million Barrels of recoverable crude oil and a production capacity of 110,000 barrels a day field life.

Terra Nova is owned by Petro-Canada 33.99%; Mobil Oil Canada Properties 22.00%; Husky Oil Operations ltd. 12.51%; Norsk Hydro Canada Oil & Gas 15.00%; Murphy Oil Company Ltd. 12.00%; Mosbacher Operating Ltd. 3.50% and Chevron Canada Resources 1.00%.

WHITE ROSE

In March of last year, Husky Oil and joint-venture partner Petro-Canada proposed development of the White Rose oilfield, located in the Jeanne d'Arc Basin, 360 kilometres (223 miles) east of St. John's. The field consists of both oil and gas pools with an estimated 36 million cubic metres (230 million barrels) of recoverable oil. Output is expected to be approximately 100,000 barrels a day. Projected first oil is 2003-2004.

NOVA SCOTIA

SABLE

The Sable Offshore Energy project was Canada's first offshore natural gas project. It began production on Dec. 31, 1999 and is set to start phase two in 2004 .

The Sable project lies approximately 160 - 300 kilometres (100 - 186 miles) southeast off Nova Scotia's east coast, 10 - 40 Kilometres north of the Scotian Shelf. It's 230 kilometres (140 miles) from Halifax to the Thebaud main production platform.

Production levels averaging 500 MMcfd are expected throughout the project, which has a life expectancy of 25 years. Since first gas, it has produced approximately 3.5 billion cubic metres of natural gas, from 6 fields. Established reserves of 171 billion cubic metres (6 trillion cubic feet) have been confirmed and estimated recoverable reserves of 99 billion cubic metres (3.5 trillion cubic feet).

In addition to gas, the project also produces approximately
7,100 barrels of propane, 4,000 barrels of butane and 11,000 barrels of condensate per day.

One of the biggest challenges developers of the Sable project faced was laying almost 300 kilometres (186 miles) of pipeline beneath the North Atlantic. The pipeline joins the Thebaud offshore central processing platform with the Goldboro gas plant onshore in Nova Scotia. It had to be designed to withstand the strong ocean currents, fishing trawler nets, ship anchors, and 15 to 150 tonnes of water pressure it would encounter in the area. Every precaution had to be taken to ensure stability of the pipes, which measure 20, 30 and 66 centimetres in diametre and about 37 feet in length.

On May 4, El Paso Corp. and Marathon Oil Co. announced intentions to conduct a feasibility study for a second subsea pipeline that would connect the Sable project to the northeastern US. Other major industry players have also expressed a similar interest in such a project.

While it made local headlines during the start-up phase of the project, Sable is now quietly focusing on maximizing its production efforts and ensuring the process runs smoothly in the coming years.

The majority of gas produced by Sable is sold to US customers, while both Nova Scotia and New Brunswick struggle to develop a lateral pipeline system to deliver the product locally.

Project owners are: Mobil Oil Canada Properties (50.8%), Shell Canada Limited (31.3%), Imperial Oil Resources Limited (9%), Nova Scotia Resources Limited (8.4%) and Mosbacher Operating Limited (.5%)

DEEP PANUKE

In February, 2000 PanCanadian Petroleum Limited announced a major discovery on the Scotian Shelf, approximately 250 kilometres (155 miles) south-east of Halifax. The discovery was made directly beneath Nova Scotia Resource's now-defunct Panuke oil field.

Exploration wells maxed-out PanCanadian's equipment when each well flowed at 55 million cubic feet of natural gas per day. The Sable project well rates are 50 - 100 million cubic feet per day, so it's not unreasonable to expect another project of the same magnitude. The Panuke P-3C well intersected net pay at 230 feet and the second well, Panuke 1-1B intersected net pay at more than 100 feet.

Investors were even more encouraged when a third well, M-79A, flowed at an average 63 million cubic feet of natural gas per day. These rates were limited by the downhole configuration of the test string. The well was drilled to a depth of 15,105 feet with a horizontal sidetrack in the main reservoir section that encountered 360 feet of net pay.

Preliminary development and planning for the project have started, and production should begin in 2005.

The company is also conducting surveys on other offshore parcels in Eastern Canada. PanCandian hold 15 blocks (exploration licenses) off Nova Scotia, covering more than 4 million gross acres.

ONSHORE

Eastern Canada's boom in offshore oil and gas production has resulted in the inevitable turn of interest to onshore developments. Although several companies, both large and small, have holdings throughout the area, none are yet producing. Indicators suggest that most of the provinces will have actual onshore production by the fall of 2001.

Nova Scotia

Five companies are currently exploring for oil and gas on 1.6 million hectares of land on mainland Nova Scotia. Although exploration onshore has been going on for more than 140 years in Nova Scotia, there has never been a significant discovery.

In Dec., 2000 PanCanadian Petroleum Ltd. announced its intention to spend $3.95 million (Canadian) exploring for coal-bed methane in the Stellarton, Nova Scotia area, near the site of the Westray coal mine disaster, where 26 men lost their lives in 1992. The exploration zone is outside of this area.

Amvest Nova Scotia has been exploring for coal -bed methane in Nova Scotia since 1994 and it recently joined forces with Nova Scotia Power to explore in the Westray mine area, as well.

CORRIDOR RESOURCES INC.

One of the most persistent players in onshore petroleum exploration of Eastern Canada has been Corridor Resources, Inc. Since 1995 the junior oil and gas exploration company expanded to holdings of 195,000 acres, to 5,650,109 net acres of petroleum exploration licenses in New Brunswick, Quebec and Prince Edward Island.

On April 16, the company announced that flow testing of the McCully No. 2 well, 12 kilometres northeast of Sussex, New Brunswick, has been completed.

The test reached a stabilized natural gas flow rate of 2.2 million cubic feet per day at a flowing tubing head pressure of 2,100 pounds per square inch (psi) following a three-day flow period. Indicators show gas being produced from several sands over a 400 metre gross interval, including the sand that is the main productive zone in the adjacent McCully No. 1 well. Initial analysis indicated that the well has a potential gas flow of 4.1 million cubic feet per day at the design separator pressure of 400 psi. The McCully No. 2 well is currently shut-in for pressure build-up analysis. The well is 50/50 joint venture partnership with the Potash Corporation of Saskatchewan Inc., with Corridor acting as the operator.

Corridor expects to be producing commercially from the McCully project by the fall of 2001.

ELSEWHERE

Newfoundland, Prince Edward Island and Quebec are all expected to have some onshore production in place by the end of 2001. Preliminary wells and testing have been completed in each of these three provinces.