Exploration consists of seismic surveys and exploration drilling to determine the existence of commercial petroleum reserves in licensed areas. These activities are expensive in offshore areas, with wells on the Scotian Shelf typically costing in the $40-50 million range, and those in deep water off the Shelf costing in the range of $60-80 million. Exploration may be carried out over a long period before a commercial discovery is made (the success rate for exploration wells on the Scotian Shelf is about one in ten). Note that the first major development project in Nova Scotia (Sable) took place in the late 1990s, some 20 years after the discovery well was drilled.

Exploration work is capital-intensive and requires the use of expensive and highly mobile equipment, including seismic vessels, drilling rigs, supply/support vessels and helicopters. Typically, these are owned and operated by specialist multinational companies that undertake exploration for petroleum companies on a contractual basis. Onshore activity to support the offshore is typically concentrated at one shore base, airport/heliport and administrative centre, which may be at considerable distance from the concession blocks being explored.

Activity levels during the exploration phase are highly variable. Experience shows that companies can terminate their efforts for a variety of reasons including poor exploration results, better prospects elsewhere, a global recession in exploration, or an unwillingness to comply with requirements for local preference, taxation and/or environmental protection.

Offshore oil and gas exploration on the Scotian Shelf spans a 40-year period. Mobil Oil Canada received its first offshore license in 1959 for the Sable Island block. Mobil began its first seismic program in 1960 and followed this with a drilling program in 1967.

Up to the end of 2001, the industry had acquired several hundred thousand km of seismic data and drilled some 140 exploration/delineation wells. Drilling activity has varied in intensity over the years, with success the main driver in the number of exploratory wells drilled. Of the 72 exploration and delineation wells drilled during the late 1960s and 1970s, eight resulted in Significant Discoveries.

Combined with incentives under the National Energy Program, this success provided the impetus for another 52 exploration and delineation wells in the 1980s. These resulted in a further 14 Significant Discoveries. Most of these are relatively small, yet potentially economic, gas fields. Exploration activity during the 1990s was relatively light, with nine wells drilled including the Deep Panuke discovery well.

Activity during the 1990s was dominated by field development, with a total of 38 production wells drilled for Cohasset-Panuke and Sable Offshore Energy Project (SOEP). Only six exploration wells were drilled. Activity picked up in 2000, following completion of SOEP. To mid-2004, another 22 exploration and eight production wells have been drilled. Table 7 provides details on the number of wells by type up to 2004. These exploration wells yielded generally poor results.

The Significant Discoveries (plus Deep Panuke) contain estimated recoverable reserves of just over 170 million cubic meters (six trillion cubic feet) of natural gas, and 35 million cubic meters (220 million barrels) of oil and condensate⁴. The Marathon Annapolis well drilled in 2001-2002 was the first deep water well and encountered enough hydrocarbons to prompt Marathon to state they would be exploring the block further. CNSOPB (2002) estimates deepwater potential to be between 425 and 1,160 million cubic meters (15 and 41 trillion cubic feet) of natural gas. The Nova Scotia Department of Energy estimates total discovered and undiscovered resources to be approximately 1,130 million cubic meters (40 trillion cubic feet).

Field development follows once a gas or oil field or fields have been deemed by the operating companies to be commercially developable. This could occur many years after the discovery because of regulatory, market, financing or engineering considerations. A development project consists of the design, construction and installation of production equipment, including systems to bring the oil and/or gas to shore (this could by tanker or pipeline in the case of oil, or by pipeline in the case of gas). Development also includes the drilling of production wells to extract the hydrocarbons (Table 8). The number of wells depends on the size and geology (porosity and permeability) of the field.

• Cohasset-Panuke Project: a relatively small oil project, this was the first offshore development on Canada's East Coast. The project comprised the Cohasset and Panuke fields, discovered in 1973 and 1986, respectively. Development took place in 1991-92. Production began in 1992 and ended in 1999, with the field producing about 45 million barrels of light oil. A shuttle tanker transported oil from a storage vessel moored at the field to refineries. The project had a capital cost of about $500 million and annual operating costs in the $110 million range (Table 8).
  
  
• Sable Offshore Energy Project (SOEP): a natural gas development consisting of six fields, it is Nova Scotia's first major offshore project. It took many years to reach the development stage. The discovery well forming the core of the project was drilled in 1979. The first attempt to develop these fields (the Venture Offshore Development Project) was halted in 1986, when market conditions proved inadequate.
  
  The project was resurrected in the 1990s as markets strengthened and sufficient gas reserves were brought into play. Engineering commenced in 1997, with field development occurring during 1998-1999. Production commenced in late 1999. The project is being developed in two phases (tiers). Tier 1 ties in three fields (Thebaud, Venture and North Triumph), with average daily production in the range of 400-550 million cubic feet. Tier 2 is underway, with development of Alma and South Venture.
  
  The original estimate of 3.2 trillion cubic feet of recoverable reserves has been downgraded to 1.7 trillion cubic feet because of poor reservoir characteristics. The gas is in place, but it is more costly to recover than originally anticipated. Capital costs for the project are estimated at $3.0 billion, with $2.0 billion spent in Tier 1 and $1.0 billion in Tier 2.
  
  
• Deep Panuke: located some 65 km to the southwest of Sable Island, this project is in the planning stage, with no development plan or schedule yet approved. Several exploration and delineation wells have been drilled.

During the production phase, the hydrocarbons are produced at the field, processed and transported to shore facilities by pipeline or tanker. The production phase for a large field can last for several decades, although for small fields it could be much shorter (less than ten years).

• Cohasset-Panuke had a field life of just over six years, with annual operating costs in the $110 million range.
• SOEP production was originally expected to last over 25 years, but reduced recoverability could constrain this to about 15 years. Tying in other significant discoveries could extend field life. Annual operating costs are estimated at $130 million.

Decommissioning refers to the process of dismantling and removing structures and equipment rendered obsolete when the producing gas or oil field has exhausted its commercially productive reserves. The Cohasset oil field off Nova Scotia was decommissioned in 2000 after operating for about seven years. Costs are estimated at $50 million.

Offshore oil and gas projects tend to be international in scope no matter where they are implemented. This is as much the case for Scotian Shelf projects as those developed in the North Sea, Gulf of Mexico or on the Grand Banks. A proportion of the spending occurs outside the national economies where the development occurs. This proportion varies depending on the capabilities and competitiveness of domestic vs. international suppliers.

• Exploration: Nova Scotia suppliers have been exposed to demands arising from offshore exploration for about 40 years, and content in exploration expenditures is typically in the 35% range (about $18 million per well). A supply capability consistent with the fluctuations and risks associated with the industry has developed in the province. Companies have developed the capability to meet demands for such services as marine and air support (supply vessels and helicopters), catering, technical and scientific consulting, and rig labour. The level of uncertainty is too great to support investment in rigs and other mobile offshore equipment (crane barges and pipelaying vessels).
  
  
• Field development: Nova Scotia suppliers had no exposure to most of the goods and services demands arising from an offshore field development prior to Cohasset- Panuke. Joint venturing allowed some deficiencies to be addressed resulting in about 37% Nova Scotia content ($184 million). This was accounted for mainly by facilities construction, marine support services and labour content in drilling. For SOEP, Nova Scotia content is estimated at 31% ($712 million), accounted for mainly by offshore and onshore facilities construction, marine and air support services, and labour content in drilling.
  
  
• Production: A higher proportion of annual goods and services requirements are met from local sources during production: about 40% ($43 million) in the case of Cohasset- Panuke and 50% ($67 million) for SOEP. This is accounted for largely by wages and salaries and service support (marine, air and maintenance). Offshore projects may also contribute to an economy through their returns on investment and any royalties paid to host governments.

The importance of the offshore oil and gas industry in the Nova Scotia economy increased substantially during the second half of the 1990s, with the contribution to provincial GDP rising from $78.5 million in 1995 to an estimated $1,120 million (current dollars) in 2001.⁵

Employment as measured in full-time equivalents (FTE) increased from 340 in 1995 to 2,218 in 1999 at the height of the SOEP development. It declined to the 1,140 range in 2001, attributable to SOEP production, Encana planning for Deep Panuke, and on-going exploration. These figures include those employed directly by the offshore companies as well as those employed by the major contractors and service companies whose activities are inextricable from the offshore companies themselves.

Most of the hydrocarbons produced are exported. Oil production from Cohasset-Panuke was shipped directly from the field to refineries outside the province. Most of the natural gas produced by SOEP is shipped by pipeline to the U.S. northeast. Some is sold on the Nova Scotia market (mainly for electrical generation), though much of that was exported since it proved cheaper to burn oil. Exports increased from a peak of $155 million during the life of Cohasset-Panuke (1992- 1999), hitting $1.2 billion in 2001 as SOEP reached maximum production (this coincided with a sharp rise in gas prices in the U.S. due to abnormally low temperatures and supply shortages). Export value dropped to just over $800 million in 2002 as prices moderated.

The contribution of the oil and gas industry to household income increased seven-fold between 1995 and 1999, rising from $16 million during the early years of Cohasset-Panuke production to just under $180 million during SOEP development. Household income declined by about half by 2001, attributable mainly to the transition of SOEP from development to production.

The contribution made by the oil and gas sector to the Nova Scotia economy is summarized in Table 9. It is worth noting that Table 9 includes as direct industry activity many activities ordinarily classified as indirect. For example, many of the inputs needed to develop or produce a field could be carried out by the operating company or contracted out to third party contractors. If carried out by the operating company they are direct activities, if carried out by a contractor they are considered indirect (from an economic impact perspective). The distinction is somewhat artificial in the case of offshore oil and gas because operating companies tend to contract out for almost all inputs. This means that direct employment is relatively low and indirect employment is relatively high. To avoid confusion and to simplify the economic impact analysis, we treat most activities as direct since this accords with the general understanding of the nature of the input activities in question.