06 April 2006

Hebron background

The Hebron-Ben Nevis is the second largest of the four major oil discoveries offshore Newfoundland and Labrador. Hebron-Ben Nevis is located in the Jeanne D'Arc Basin, approximately 300 kilometres east of St. John's Newfoundland and Labrador.

It consists of Hebron, discovered in 1981 West Ben Nevis and Ben Nevis (discovered 1980) with estimated recoverable oil reserves of between 400 and 700 million barrels. The bulk of the oil is heavy (API 20), making recovery more complicated than at Terra Nova, Hibernia and White Rose.

The fields were considered non-commercial for some time after discovery owing to the physical difficulties in the field, including the presence of large quantities of heavy oil.

The four corporate partners - ExxonMobil, Chevron Canada, Norsk Hydro and Petro-Canada - drilled appraisal wells in 1999-2000 and began evaluating the potential for development in 2000. This work was discontinued in 2002. After some delay, the partners concluded a joint operating agreement in April 2005 and shortly after began discussions with the Government of Newfoundland and Labrador on a royalties and benefits agreement.

These discussions concluded on or around 31 March 2006 with no deal being reached. Chevron Canada announced the suspension of the project and began redeploying its personnel in St. John's to other projects around the globe. There is no indication that the partners will pursue the project in the near term (less than five years).

Development cost of the field to first oil was estimated by the partners at between CDN$3.2 and CDN$5.2 billion, making it the second most costly project in the current offshore. The preferred production mode was a gravity-based structure (GBS). Experience gained on Hibernia allowed the companies to reduce the size and hence the cost of the GBS. Field life is estimated at 20-25 years pending further delineation.

Left: Built between 1990 and 1997, the Hibernia gravity-based structure contains drilling rigs, living quarters, oil storage and other facilities to sustain production at Newfoundland and Labrador's largest offshore oil and gas field. [Photo: Greg Locke/Picturedesk International]

While it unlikely in the near-term, as technology develops or as other options emerge, the partners may switch production modes to a less costly method than GBS. This would reduce the local industrial benefits to Newfoundland and Labrador but improve the corporate profitability of the project.

Media reports this week indicated that the provincial government would have received CDN$8 to CDN$10 billion in royalties over the life of the project. This does not include other provincial revenues related to oil production. The current provincial debt, on a consolidated basis, is approximately $11 billion.

In 2006, the Government of Newfoundland and Labrador estimated that it will receive more than CDN$700 million in royalties from current production and an additional CDN$224 million in corporate taxes. A similar or improved ratio of royalties to corporate taxes could have been be expected from Hebron given that project royalties from the development were equal to or greater than royalties from the three existing developments combined.

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