Sable Island, a low, 44-kilometer-long strip of sand lying some 300 kilometers southeast of Halifax, Nova Scotia, has a fearsome reputation among seafarers. Christened the "graveyard of the Atlantic," Sable's treacherous, shifting shoals, which stretch for more than 160 kilometers, have claimed more than 350 ships since 1583. Yet today, Sable Island is the birthplace of a new industry. Natural gas began flowing from a collection of offshore fields around Sable Island at the close of 1999. Thebaud, North Triumph and Venture fields now produce more than 500 million cubic feet of raw gas per day, which streams into a processing plant onshore Nova Scotia and thence down a newly built 30-inch mainline to New England's vibrant energy markets. Members of the Sable Offshore Energy Project (SOEP) group are Mobil Oil Canada (a subsidiary of Exxon Mobil Corp.), Shell Canada, Imperial Oil Ltd., Mosbacher Operating Ltd. and Crown-owned corporation Nova Scotia Resources Ltd. The consortium has completed its C$2-billion Tier I development, which involved drilling 10 wells, setting three production platforms, and constructing an offshore gathering system and onshore facilities. "We're getting beyond some of the facilities issues and constraints involved with the start-up-for the last few months we've been producing at close to the pipeline's current capacity. The wells are delivering as we had hoped," notes Michael Fitzgerald, Calgary-based manager of exploration, Imperial Oil. Tier II is scheduled for 2004 to 2007. That phase will bring South Venture, Glenelg and Alma fields on stream and sustain production levels as the initial fields decline. Over a 25-year life, 3.5 trillion cubic feet (Tcf) of gas will be recovered from the six fields, which lie in water depths between 20 and 80 meters. "There's always the option to accelerate Tier II if the market is there, the price is right and the technical work is completed," says Fitzgerald. SOEP has been a long time coming. Since 1967, when exploration began offshore Nova Scotia, 22 significant discoveries have been made-all in the Sable subbasin-containing about 6 Tcf of recoverable reserves. But the finds lay fallow for decades until improved technologies and higher gas prices finally made the economics workable. The six fields comprising the SOEP project are the crown jewels of past efforts; most all of the remaining accumulations contain estimated recoverable reserves of less than 200 billion cubic feet (Bcf) of gas apiece. Venture, the largest find made to date on the shelf, holds recoverable reserves of around 1 Tcf. Certainly, the Sable area is the most heavily explored portion of the vast Scotian offshore, which covers an area of 400,000 square kilometers. All told, just 104 exploratory tests and 64 delineation and development wells have been drilled in Nova Scotia's offshore, mainly in the Sable subbasin, in water depths less than 100 meters. Typical fields in the Sable area are structural traps related to growth faulting associated with deposition of the immense Sable delta. Production is mainly from Cretaceous deltaic and shoreline sandstones, and both overpressured and normally pressured reservoirs exist. A 1989 study by the Geological Survey of Canada assessed the total potential recoverable gas resources of the Scotian shelf at 18 Tcf, with 12 Tcf still to be discovered. Now that the first infrastructure is in place at SOEP, attention is turning to exploring for that gas once again. "The Sable partners have shot a considerable amount of 3-D seismic on the shelf in the last few years, and we have coverage over most of our acreage," says Fitzgerald. In 1999, Shell, Mobil Canada and Imperial picked up six additional exploration licenses in and around the SOEP infrastructure. The 3-D seismic provides a much clearer picture of the subsurface than did earlier 2-D surveys, he says. "Quite a few wells have been drilled in this area over the years, and when we combine the well control with the new 3-D data, we see these lands as being quite prospective." Indeed, the partners have just spudded their first exploration well, the Mobil Canada-operated Emma N-03. The Emma well lies on the north side of Sable Island. The Santa Fe Galaxy II was moved from Thebaud platform to the Emma location to drill the well, projected to a true vertical depth of 4,975 meters. "These wells are quite expensive, but the 3-D seismic gives us a good idea of the risks," says Fitzgerald. "We feel comfortable with the potential." Unquestionably, offshore Nova Scotia is finally coming of age. "Now that the Sable project is up and running and we're beginning to develop an infrastructure, offshore Nova Scotia is getting much more attention," says Jim Dickey, Halifax-based chief executive officer of the Canada-Nova Scotia Offshore Petroleum Board. Indeed, the CNSOPB's sale in April 1999 raised eyebrows throughout the world oil community. Some 19 licenses totaling 5.5 million acres were awarded for work commitment bids of C$592 million, by far the largest sale in the CNSOPB's 10-year history. "The success of that sale was due to several factors," notes Dickey. "The Sable partners showed that they could move their project ahead with world prices, and that they could do the job on time and within budget. The government of Nova Scotia also put together a generic royalty agreement with attractive terms." The CNSOPB's licenses compete quite favorably with those in other areas. A license runs for nine years, split into a five- and a four-year term. A well must be drilled before the end of the fifth year, or security can be posted to gain a one-year extension. Companies put up a promissory note equaling 25% of their initial five-year work commitment, which is credited back as the work proceeds. And when a company wins a block, it has a generous amount of acreage to explore. Most Nova Scotia offshore blocks contain well over 100,000 acres, and some many times that amount. The Board was established in 1990 after the Province of Nova Scotia and the federal government set aside their jurisdictional claims for ownership and signed a political accord for the joint administration of the offshore resources. On behalf of both governments, the CNSOPB manages all offshore petroleum matters from the low-water mark along the shore to the international and provincial boundaries. Acreage is still available-the CNSOPB continues to offer parcels each year. Its October 1999 sale tendered 11 blocks, mainly lying along the shelf edge. Those leases fetched work commitments of C$61 million. "We have eight licenses out on call now, with bids due at the end of October," says Dickey. "So far, we have C$830 million in minimum work commitments on 42 exploration licenses. After we receive bids on those additional eight parcels, we could be looking at exploration work commitments of around C$1 billion over the next five years." The CNSOPB forecasts that at least 15 to 25 offshore wells will be drilled during that time, including deepwater drilling. "Our activity is market-driven," notes Dickey. "We're in a global environment and we know that we have to be competitive. The message is getting out to industry that this is a good, sound region for investment." News of a substantial new discovery on the shelf has also boosted excitement. About 40 kilometers west of Sable Island lies the Copan project. Copan's two small oil accumulations were Canada's first offshore project: Cohasset and Panuke fields produced 44.4 million barrels of oil between 1992 and 1999 from Cretaceous sandstones found at depths between 1,750 and 2,300 meters. Last year, Calgary-based PanCanadian Petroleum Ltd. made the most significant discovery in Atlantic Canada in more than a decade when it drilled a deeper-pool wildcat from the Panuke jacket. PanCanadian's first two deep tests-a discovery and a delineation well-were outstanding. In April 1999, the 4,380-meter PP-3C well tested at 55 million cubic feet per day from the Jurassic Abenaki, a carbonate reservoir that trends along the shelf edge in water depths between 25 and 50 meters. The flow on the discovery, which encountered net pay of 68.5 meters, was limited by the rate of the equipment. The PI-1B confirmed the find in January 2000, testing 52 million cubic feet of gas per day. Net pay thickness in the confirmation well was in excess of 30 meters; that flow rate was also restricted by the facilities. "Away from the Panuke jacket, we've just finished one delineation well and are drilling one more," says Larry LeBlanc, Halifax-based vice president of East Coast operations. The Rowan Gorilla III, the rig that was previously on the Panuke platform, drilled the H-08 well, which encountered 99 net meters of Abenaki pay. That well, drilled to a true vertical depth of 3,898 meters, tested more than 50 million cubic feet of gas per day, again equipment-limited. At press time, the Rowan Gorilla V was also drilling ahead on the M-79 well, projected to a total depth of 4,677 meters. The Gorilla III is now drilling the F-09 new-field wildcat location toward a projected depth of 4,800 meters. These wells typically take 90 to 100 days to drill, and cost in the C$25- to C$30-million range. "We're trying to prove up enough reserves to make the deep Panuke project commercial," notes LeBlanc. "We'd like to find a reserve size in the range of 1 Tcf or greater." The find is huge for PanCanadian, which holds 100% of the deep Panuke rights. Although Nova Scotia Resources Ltd. owned 50% of the shallow oil project, it elected not to participate in further drilling. Meanwhile, PanCanadian has been winding up the shallow Copan project. "We ended production at Copan in mid-December of last year, and over the last six months we've been decommissioning the wells, both at Panuke and Cohasset fields," says LeBlanc. "We've been reconfiguring the well slots on the jacket to allow us to conduct exploration and delineation drilling from the old platforms." Jeff Rose, general manager, North American Frontiers, notes that PanCanadian's acquisition of the Copan project from operator Lasmo in early 1996 was the company's initial step into offshore Nova Scotia. On the heels of that purchase, in 1997 the company began participating in the calls for bids for exploration licenses. "1999 was a huge year for us in license acquisition," says Rose. "The spring sale was primarily focused on the deep water, and we worked in a partnership with Marathon, Murphy Oil and Norsk Hydro. Our group picked up three blocks covering 1.2 million acres, and we picked up another block on our own covering 278,000 acres." The company was also awarded several blocks in last fall's sale, which was focused along the shelf edge. From its modest start with Copan four years ago, PanCanadian has grown into one of the leading oil and gas explorers offshore Nova Scotia. The Calgary firm now holds interests in 15 exploration licenses covering more than 4 million gross (nearly 2.5 million net) acres, located both in the traditional shelf play and in the emerging deepwater play on the slope. Unquestionably, the potential of the deepwater play has grabbed the oil industry's attention. During the flurry of offshore drilling that Canada's East Coast enjoyed in the early 1970s, drilling past the shelf break was not technically possible. Now companies eagerly eye this new frontier. "No wells have been drilled in the Scotian salt province deepwater play, but there are certainly lots of structures, and some very large ones that need to be drilled," says Rose. PanCanadian's interest in the deepwater Scotian shelf sprang from its efforts in the deepwater Gulf of Mexico. "Seismically, the play we are chasing is very similar to the Gulf of Mexico," he says. "Both areas have turbidites that are caught up in salt-related structures, although the Scotian shelf has Cretaceous and Jurassic sediments and the Gulf of Mexico is a Tertiary play." Exploration on the Scotian slope is in its early days, he notes. "We have great hopes. The deepwater play is in the first stage of exploration, and we're aggressively pursuing it." PanCanadian and its partners have been acquiring huge volumes of 3-D seismic surveys over their deepwater acreage, and are immersed in processing and interpretation. The company expects to spud its first slope well in the latter half of 2001. Calgary-based Canadian 88 Energy Corp. is another firm that is intrigued with the potential of the Scotian slope. "We are very much an exploration company, and we are driven by opportunity," says Al Clark, manager of frontier exploration. "We entered offshore Nova Scotia in 1999 because there was a great deal of land posted on a new, promising trend in the deeper water." Canadian 88 drew parallels between the Scotian slope and productive areas such as the deepwater Gulf of Mexico, offshore Brazil and offshore West Africa. "Industry had requested the posting of the lands off of Nova Scotia to pursue the same types of plays. Not many companies were active on Canada's East Coast at that time, and we thought there might be a limited number of bidding groups," says Clark. "It was not out of the question for a smaller company like ourselves to get in on the ground floor with some modest bids," he notes. The firm acquired 9,000 kilometers of recent 2-D seismic to aid in its evaluations of the available blocks. In the April 1999 sale, Canadian 88 won two large tracts totaling 950,000 acres for work commitments of C$29.9 million. It added two smaller blocks at the October 1999 sale for work commitments of C$7.6 million. "We picked up a total of 1.5 million acres in four blocks, in water depths varying from 200 to 3,000 meters," says Clark. "Most of our efforts so far have focused on the portions of our blocks in water depths down to 2,000 meters." Clark notes that the Scotian offshore shares traits with other prolific deepwater areas. "We have a salt basin and salt structures, and we have catch basins for turbidite sand deposition. We see features on seismic that look for all the world identical to features that are productive in other deepwater areas." The deepwater play covers a vast area, spanning about 1,000 kilometers from Georges Bank to the Laurentian Channel. "In that entire area, only three wells have been drilled that provide any information whatsoever," says Clark, "and the most recent one was drilled in 1986. We certainly recognize that the lack of well control makes this a high-risk exploration play." It's an open question whether the Scotian slope will yield oil or gas. "Right now, it's a flip of a coin. We don't have a good sample of source rocks, and much is unknown about the basin history. Because of the abundance of gas in the Sable Island area, most people think the deepwater play will be gas-prone, although some work seems to suggest that the deepwater may be more oil-prone." Earlier this year, Canadian 88 announced that Kerr-McGee Corp. had agreed to join its efforts, acquiring a half interest in all of Canadian 88's offshore Nova Scotia lands. In return, the Oklahoma City-based independent paid 3-D seismic acquisition and processing costs, took over placement of the promissory notes and assumed operatorship of the properties. "Kerr-McGee is the kind of partner we were looking for," notes Clark. "It has operated all over the world, and has the staff and experience to move this play forward." The partners have in hand 4,000 square kilometers of 3-D seismic over their acreage. "Our seismic is done, and we're both working on further processing and interpretation. We will be well on our way to having locations picked next spring," says Clark. "If all goes well with licensing and we can secure an appropriate drilling vessel, we will be drilling by early 2002." Imperial Oil is also playing the deepwater. Fitzgerald notes that the company picked up a 100% interest in two slope blocks in the April 1999 sale. "Right now, we're acquiring 3-D seismic on the deepwater blocks," he says. "The play is an unknown for us, because only a few wells have been drilled in the uppermost part of the slope. We see an abundance of seismic features, but it's very high-risk exploration due to the lack of well control." Imperial plans to finish acquiring 3-D seismic, but will proceed ahead at a slower place than on its lower-risk Scotian shelf prospects. "Overall, activity on the slope will grow by leaps and bounds because so many blocks have been leased," he notes. "But exploration in a play like this will require a cautious approach because the wells are so expensive and the risks so high." As alluring as the deepwater play might be, other firms are investigating areas that are not quite so pricey. The CNSOPB has also granted licenses in the shallow-water Cape Breton and Gulf of St. Lawrence areas. Dallas-based Hunt Oil holds two licenses directly to the east of Cape Breton, and Halifax-based independent Corridor Resources holds one to the west. Both companies wish to shoot seismic on their blocks, and the proposals have stirred much local controversy. The collision between the oil and gas newcomers and the established fishing interests is hardly a surprise in Nova Scotia. (For more on this, see "The Prize: Sable Island," Oil and Gas Investor, June 1997.) Corridor's Cheticamp block, covering 615,000 acres, lies on the west coast of Cape Breton Island in the Gulf of St. Lawrence. The license area is adjacent to the East Point gas discovery made in 1978 by Hudson Bay Oil & Gas (now BP) in the Prince Edward Island sector of the Gulf. The East Point well tested natural gas at a rate of 5.5 million cubic feet per day. "It sits as an orphan field, too small to be developed commercially on its own," says Norm Miller, president. "It's our belief, based on working the old seismic that had been run in the area, that there are additional prospects." Corridor initially planned to acquire new seismic on the acreage this year, but has opted to delay exploration activities until 2001. "We want to wait for some environmental studies that are under way to be completed, and to allow the community processes to work," says Miller. "There are some naysayers who just don't want exploration," he notes. "They claim that we will damage the fishery with seismic." Corridor has met with the local residents, and many welcome the activity, he says. At press time, the Inverness County council had voted to keep the door open for a continuing relationship with Corridor. "We're looking for relatively shallow prospects, so we can use very small airguns," says Miller. "We can carry out exploration activity responsibly, carefully and at the right times of the year so we don't interfere with the fishermen." Even the onshore Maritime Provinces are enjoying a revival of interest in exploration. "Up until now, natural gas in the Maritimes has been just a big yawn because of the market difficulties," says Miller. "Now that the Maritimes & Northeast Pipeline is in place, the whole area is attracting more attention. It's a great stimulus for us explorers to have the pipeline in the region." Indeed, Corridor, formed in 1995, took its name from the pipeline corridor that was planned to carry the SOEP gas through the provinces. Today the firm holds an interest in 5 million acres of leases in several different plays. Unquestionably, New Brunswick has been the locus of much of the industry's activity, most of it near the old Stoney Creek Field in Albert County. Discovered in 1909, it is the only commercial onshore field that has been found in the Maritime Provinces. It contained 21 million barrels of oil-in-place in the Lower Carboniferous Albert Formation, at depths between 500 and 1,100 meters. Only 830,000 barrels were produced, however, because of poor production techniques. The field also made more than 28 Bcf of natural gas, which was sold to markets in Moncton and the town of Hillsborough. "Over the years, there has been a lot of unsuccessful follow-up drilling," says Miller. "The area has surface shows and complex geology. Now, with the pipeline coming through, interest is surging again." Last year, Corridor farmed out half of its 100% interest in 312,000 acres in the Sackville and Elgin subbasins to Columbia Natural Resources of Charleston, West Virginia. As part of the agreement, Columbia assumed operatorship of the properties. This July, the partners spudded their TCH G-100, located approximately 12 kilometers northwest of Sackville. The well is the first of a series of slim-hole tests that will evaluate the eastward extension of Stoney Creek, located 17 kilometers to the west. The TCH G-100 well is projected to 1,600 meters at an estimated total cost of C$311,000. To the west, in the Elgin subbasin, Columbia and Corridor drilled the Will DeMille #1 exploration well last year. The well, designed to test the Albert sequence in a basinward position from an old well that had tested small amounts of gas, was a geological surprise to the partners. "We've had to significantly revise our understanding of the geology of the area," notes Miller. "We realized that we needed additional seismic, and that the area was more complicated than we originally predicted." This year, Corridor is drilling a 2,400-meter well with the Potash Co. of Saskatchewan in the western part of the Elgin subbasin. Here, the company owns a 100% interest in 130,000 acres. "The Potash Company shot a 3-D survey last summer to look at the detailed geology in the area, because water was seeping into its mine," says Miller. The shoot, one of the first onshore 3-D surveys in the Maritimes basin, revealed an attractive gas prospect beneath the potash operations. The firms agreed to partner on the C$1.5-million well. Columbia Natural Resources, lately the busiest company in New Brunswick, is also involved in a venture in the southeastern part of the province with independent MariCo Oil & Gas Corp. Columbia took a 50% interest in and assumed operatorship of 17 tracts covering more than a million acres, including a block MariCo had farmed into from J.A. Seglund. Columbia also purchased a 50% working interest in MariCo's Downey #1 discovery well. The Downey was the first significant gas find in New Brunswick in more than 50 years. The well, drilled about 6 kilometers south of Stoney Creek, tested gas from the Albert at the rate of 2 million cubic feet per day. The discovery is currently shut in. Columbia is very aggressively pursuing an exploration program in the province, says Darcy Spady, general manager of the firm's Fredericton-based Canadian subsidiary. "We're drilling, core-hole testing, stimulating and completing wells in New Brunswick, and we're continuing aeromagnetic and seismic data programs started by our partners MariCo and Corridor." New Brunswick is an Appalachian-style play, says Spady. "It's a complex area, and we're experimenting to find the most cost-effective technologies. We use Appalachian technology where possible, such as air drilling with percussion bits, because the rock types are similar." Local equipment, such as modified hard-rock coring rigs, can also be effective in oil and gas operations in the province, he notes. "We're optimistic for the future, and we're certainly here for the long haul. We expect to drill in the neighborhood of 10 wells per year for the next several years, although in the future development work could double or triple that number," Spady says. Eight wells have been drilled in New Brunswick this year and the Potash Co. well is currently drilling, says Clint St. Peter, hydrocarbon geologist, New Brunswick Department of Natural Resources & Energy. MariCo operated two of the tests and Columbia operated six. Thanks to MariCo's success with the Downey well, explorers have been emboldened to step further away from Stoney Creek Field. "Most of the exploration is taking place in the southeastern-most corner of the Moncton subbasin," says St. Peter. "It's not really the same trend as Stoney Creek, because that accumulation lies on the north side of the basin and the new drilling is on the south side. But people are looking for the same Albert objective, which is a lacustrine sandstone reservoir." Onshore Nova Scotia is seeing activity as well. The province currently has 15 active exploration licenses, including two issued for coalbed methane. Altogether, some 100 wells have been drilled in the province, mainly targeting Carboniferous objectives. More than a third of these tests recorded petroleum shows. Last summer Hunt Oil drilled the first conventional oil well in more than a decade in the province's Windsor subbasin. The Colchester County test, located near the town of Truro, was projected to a depth of 1,675 meters. That well is still a tight hole. The most active driller in Nova Scotia has been Amvest Nova Scotia Inc., a private company based in Charlottesville, Virginia. Amvest holds two coalbed methane licenses, which total about 160,000 acres. A Nova Scotia Power affiliate is its 50% partner in the coalbed ventures. Amvest independently has four conventional exploration licenses covering 600,000 acres in the province. In addition to its Nova Scotia activity, Amvest operates exploratory coalbed methane projects in West Virginia, North Carolina, Illinois and Oklahoma. Amvest has drilled three wells in Pictou County in the Stellarton Basin and two in Cumberland County, in the northwest portion of the province. "We've performed a lot of reservoir evaluation, production testing, gas content analysis and resource assessment on our wells," says exploration manager John Sinclair. "We're encouraged by what we see. Now we're looking for another partner because we'd like to drill more wells." The resource is significant-coal has been mined in Nova Scotia for 200 years. In the Stellarton Basin, the coal seams range in depth from 200 to 1,300 meters, and gas contents range from 200 to 500 standard cubic feet per ton. "The gas contents are well within the range of productive coals in the U.S.," he notes. "We have as much as 65 meters of net coal in a well in the Stellarton, and as much as 25 meters in the Cumberland Basin." Over the next year, Amvest plans to drill three to four wells in the Stellarton Basin and two in the Cumberland Basin. "The Stellarton Basin is a confined area, but it has very thick coals. There's at least 50 Bcf of gas per square mile in place there," says Sinclair. "In the Cumberland Basin, which is much larger, we estimate about 1.5 Tcf of total gas in place." Amvest plans to move ahead with exploration on its conventional licenses also. It is reprocessing existing seismic data and expects to shoot some new data toward the close of the year. "The main target for the conventional play is the Albert Formation, the same reservoir that produced at Stoney Creek in New Brunswick," says Sinclair. "On our acreage the Albert occurs between 12,000 and 18,000 feet deep." Even quiet Prince Edward Island has been enjoying some attention lately. Only 15 exploratory wells have been drilled on and around the little province, which is just one-tenth the size of neighboring Nova Scotia. Four companies hold permits covering a million acres on PEI; Corridor drilled a well in Queens County in 1997 that it has suspended as a natural gas discovery in tight, low porosity sands. Corridor's Green Gables location is only a few miles from the idyllic rural setting made famous in Lucy Maud Montgomery's Anne of Green Gables. The prospect, a large structural feature underpinned by a Windsor salt pillow, was first defined by seismic in the early 1970s. The initial well, drilled in 1972 by Hudson's Bay Oil & Gas, encountered some gas-bearing sands at depths of 2,300 meters. The company ran a drillstem test and recovered an estimated 20,000 cubic feet of gas per day. Corridor's 2,293-meter Green Gables #2 well, drilled in partnership with Vancouver-based Dobrana Resources Ltd., cut 37 meters of net potential pay. "We found a big structure with gas, in fairly tight sands. The prospective reservoir sands are clay-filled, and must be stimulated to be potentially productive," says Miller. "We've cased the well and we're researching the frac technology. There are techniques for dealing with the clay problems, and we're seeking a partner with tight gas experience." Corridor plans to acquire 3-D seismic and drill a third well on the feature further to the south. Miller estimates that the Green Gables feature contains as much as 500 Bcf of gas in place. The local gas market on PEI could easily take 20- to 30 million cubic feet per day, he notes. Additionally, the province is lobbying for a lateral from the Northeast & Maritimes system. "If that happens, we'll see more activity in this area," says Miller. Currently, all gas produced offshore Nova Scotia flows to the northeastern United States. The main line of the C$1.7-billion Maritimes & Northeast Pipeline (M&NP) stretches 1,051 kilometers from Goldboro, Nova Scotia, to Dracut, Massachusetts, northwest of Boston, where it interconnects with the North American pipeline grid. The line is capable of transporting about 600 million cubic feet of gas per day; compression and looping could greatly augment that volume in the future. The M&NP is owned by affiliates of Westcoast Energy Inc., Duke Energy, Mobil Canada and Nova Scotia Power Holdings Inc. "This fall, when we put the Halifax and St. John laterals into service, companies in Canada will begin using the gas," says Rob Whitwham, Halifax-based senior manager, marketing and business development. The anchor shipper for the Halifax lateral is Nova Scotia Power, which is converting its power generation plant in Dartmouth, Nova Scotia, to natural gas. "Nova Scotia power has contracted to move 61.6 million cubic feet per day," he says. The 16-inch St. John lateral has three major contract shippers-the Irving Oil Ltd. refinery, three facilities owned by J.D. Irving Ltd., and Bayside power generating station. These customers will take 115 million cubic feet per day. Besides adding more customers to these laterals, the M&NP is also working toward extending its system to northwest New Brunswick, northeast New Brunswick and Prince Edward Island. Supply should not be an issue, as growing Canadian demand will spur the offshore producers to accelerate their production plans and keep the lines full, notes Whitwham. "There's a high level of excitement about the arrival of natural gas in the Maritimes, not only as a new energy alternative for homes and businesses, but also because a new industry is being established. Natural gas has the potential to be a great economic generator for this part of Canada," he says. If the plans of the explorationists pan out, the Maritimes will have abundant gas supplies-both offshore and onshore-to fuel a bright future. OFF LIMITS Not all of the Maritime Provinces' offshore is open to exploration. Although Nova Scotia and the federal government manage the Nova Scotia offshore area in the joint accord legislation, the offshore boundary between Nova Scotia and Newfoundland is in dispute and subject to arbitration. Permits in the Laurentian Channel that were issued by the federal government prior to the Canada-Nova Scotia Offshore Petroleum Board's formation sit in abeyance, waiting for a resolution of the issue. The target is to forge an agreement between the provinces within the next 18 months, notes Jim Dickey, chief executive officer of CNSOPB. Also, a government moratorium has been imposed in the environmentally sensitive Georges Bank area, prohibiting exploration or development in that area until 2012. "The CNSOPB has also given notice to industry that we will not accept any nominations in the Sable Gully, a sensitive area east of Sable Island that's a whale sanctuary," notes Dickey. Canada's Department of Fisheries is currently studying the Sable Gully as a potential Marine Protected Area. Further, while Newfoundland and Nova Scotia have agreements with the federal government to jointly administer exploration and development activities in their offshore areas, New Brunswick, Prince Edward Island and Quebec don't yet have such agreements, although they are under way. "This situation has retarded exploration in the Gulf of St. Lawrence," says Norm Miller, president of Corridor Resources, a Halifax-based independent. "However, we're hopeful the respective governments will increase their efforts to reach the required agreements and open up the economic potential of this offshore area." (See map page 28.)