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Canada’s East Coast teeters Lightly explored basin keeps optimism alive, despite dusters Gary Park Petroleum News Calgary Correspondent
The prospects of Canada’s East Coast becoming a growing and long-term source of oil and natural gas, especially for the U.S. Northeast, are drawing closer to the tipping point.
Several years of demoralizing drilling results have spread a cloud over the region that only a major discovery will clear away.
FirstEnergy Capital has calculated the cost of dry holes offshore Nova Scotia and Newfoundland at about C$600 million.
Pipeline plans have been put on hold and analysts are openly challenging Canada-Nova Scotia Offshore Petroleum Board optimism that seven exploration wells will be drilled this year and that operators will start venturing into the region’s deepwater prospects — all part of C$1.56 billion in work commitments on 59 license blocks.
For Newfoundland, which is expected to surpass 500,000 barrels per day from three fields by 2006, the outlook is equally worrying in an area that hasn’t seen a new discovery in almost 20 years and where majors have been shelving projects, assets are being unloaded and land sales have crumbled.
What keeps optimism alive is the relative infancy of both basins. Newfoundland has tallied less than 200 exploration wells compared with more than 5,000 in the North Sea; Nova Scotia has also logged about 200 wells against 50,000 in the Gulf of Mexico, an area roughly the same size.
Newfoundland Energy Minister Lloyd Matthews said earlier this year that more than C$30 billion is earmarked for spending over the lifetimes of East Coast projects, including C$2.1 billion in work commitments for 100 exploration licenses.
“We’re actively promoting our potential on the global stage,” he said. East Coast success needed soon But the voices from those making the high-risk decisions reflect a growing unease.
“We need a discovery fairly soon,” Gordon Carrick, vice president of East Coast operations for Petro-Canada, said in a luncheon address. “I think we are approaching a crossroads.”
David Collyer, Shell Canada’s vice president of frontiers, told a Canadian Energy Research Institute gas conference last winter that “we need to reverse the recent trend of exploration drilling (offshore Nova Scotia) and get some encouraging results.”
Paul Barnes, manager of the Canadian Association of Petroleum Producers’ office in Newfoundland, conceded: “What we do need in this basin — in Newfoundland and Nova Scotia — is some success in the next year or two ... or we certainly may lose momentum.”
One of the most anxiously-awaited decisions is expected from EnCana later this year on the future of its C$1 billion Deep Panuke gas project — scheduled to come on stream in 2006 at 400 million cubic feet per day as Nova Scotia’s second producing gas field after Sable.
To the surprise of few, EnCana said that without reserves to supplement its existing 935 billion cubic feet, Deep Panuke could be deep-sixed.
It has been granted a time-out by the National Energy Board and the Canada-Nova Scotia Offshore Petroleum Board to hunt for new reserves and wrestle with the project economics. This summer will be crucial The make-or-break point looms this summer, when EnCana drills two exploration wells at either end of the Deep Panuke reservoir.
Chief Operating Officer Randy Eresman said in May that EnCana needs to “build confidence” that the field has the reserve volumes previously estimated “before we go ahead.”
Gwyn Morgan, EnCana president and chief executive officer, took an even harder line, saying efforts are focused on a comprehensive review designed to improve Deep Panuke’s “risk-weighted return” after it became evident that the project in its present form “wasn’t going to make the grade.”
Despite the latest Canada-Nova Scotia Offshore Petroleum Board estimates that Nova Scotia’s shallow and deep water plays hold 33 trillion cubic feet of recoverable reserves — with other wildly ambitious estimates ranging as high as 100 tcf — that potential is likely to go unrealized over the near-term if EnCana pulls the plug. Production down Calgary-based consultant Ziff Energy Group has forecast Nova Scotia production will quadruple to 2 bcf per day by 2010.
Instead, volumes from Sable actually declined to 458 million cubic feet per day in the first quarter of 2003 from 530 million cubic feet a year earlier, a drop that operator ExxonMobil blamed on routine maintenance.
But analyst Ian Doig, one of the harshest critics of the Sable venture, argued the problems are more deeply-rooted and has predicted Sable could be depleted in less than half its projected 25-year life span.
Shell Canada, which owns 31.3 percent of Sable, has lowered its own share of reserve estimates to 700 billion cubic feet from 1.1 trillion cubic feet, with Collyer describing the reservoirs as a “lot more complex in terms of geology and production outlook than initially.” ExxonMobil has also written down its reserves this year and Imperial Oil announced a 16 percent write down in 2001.
In a bid to offset those setbacks, the Sable owners are moving to the next development phase that is expected to see the first of three new fields start producing late this year from reserves of 230 billion cubic feet.
Attempts to expand beyond Sable have fallen short of hopes, especially during the last year as the region has grown perplexed over costly exploration failures by ChevronTexaco, Shell, EnCana and Canadian Superior. Not all walking away But not all the majors are walking away. Imperial Oil, Canada’s largest integrated oil firm and a 69.6 percent-owned subsidiary of ExxonMobil, pulled a surprise June 5 by awarding contracts for its first deepwater exploration well that should start drilling in July.
Imperial has 100 percent exploration rights to two parcels covering 620,000 acres about 180 miles east of Halifax, Nova Scotia, and south of the producing Sable fields.
Despite the risks and high costs, the unproven potential of the deepwater play has encouraged Imperial to “test this significant opportunity now,” said Senior Vice President K.C. Williams.
John Hogg, EnCana’s vice president for Atlantic Canada, gave another boost to spirits in early June when he predicted 10 deepwater wells in the next two years, describing the potential for large new finds as “very good, although today they remain elusive.” Four exploration licenses up for bid The Canada-Nova Scotia Offshore Petroleum Board is trying to capitalize on the region by calling bids for four exploration licenses covering 620,000 acres east of the Sable fields.
The one bright exploration spot in recent years was the discovery by a Marathon Oil-led partnership at its Annapolis G-24 deepwater wildcat that needs more drilling to determine its commercial viability.
However, despite its estimates of 5 tcf to 15 tcf of reserves in Annapolis, Marathon has postponed a further exploration well until 2004.
Nova Scotia Energy Minister Ernie Fage said the partners need time to arrange financing and contract a rig. Brian Prokop, with Peters & Co., is more dubious, suggesting Marathon is “probably backing off and looking at the economics.”
Injecting some optimism into the region, Canadian Superior Energy and El Paso Oil and Gas Canada, despite the disappointment of abandoning a well in the Deep Panuke geological structure last year, announced in May they will spend up to C$60 million on a 19,700-foot well on its Marquis project this summer.
Canadian Superior estimates the potential exists at Marquis for a discovery of up to 2.4 tcf, with another 1 tcf in the offing for its wholly owned Mariner project. As well, it has identified three sizeable prospects on its Mayflower project, which it rates as similar to basins offshore West Africa, Brazil and the Gulf of Mexico, with potential for 1 billion barrels of oil or 10 tcf equivalent.
“When you hear there’s been a dry hole out there, it doesn’t really mean a lot,” Canadian Superior chief executive officer Greg Noval told his company’s annual meeting June 27.
He said Canadian Superior opted for El Paso over other potential partners because of the U.S. company’s access to key pipeline markets in the northeastern United States. El Paso delays pipeline However, even El Paso has indicated some uneasiness. In April it postponed its planned C$2.3 billion Blue Atlantic Transmission System pending a decision by EnCana to develop Deep Panuke. The 1 bcf per day pipeline was designed to serve the U.S. Northeast and Nova Scotia markets. El Paso will make a decision on a regulatory filing in late 2004.
Doubts also hang over plans by Maritimes & Northeast Pipeline, which operates the existing line from Sable to New England, to spend C$1 billion doubling capacity of the line to 1.2 bcf per day. Like El Paso, Maritimes & Northeast has been sidetracked by the Deep Panuke delay.
Oil-prone Newfoundland has taken two setbacks in the last month. Operator Petro-Canada, EnCana and Norsk Hydro have abandoned two exploration wells costing a combined C$80 million in the Flemish Pass, 300 miles east of St. John’s, Newfoundland. Using the semi-submersible Eirik Raude rig, the partners reported some oil but not in commercial quantities from the first and offered no details from the second other than saying the results will be evaluated as part of next year’s drilling program.
“We’re certainly not in a position to condemn that whole basin,” said Petro-Canada Chief Executive Officer Ron Brenneman. “These were high-risk wells going in. We recognize that.”
Newfoundland offshore oil production may have peaked at 500,000 bpd
Within three years, offshore Newfoundland may have attained its pinnacle, pumping more than 500,000 barrels per day from three fields — Hibernia at 220,000 barrels, Terra Nova at 200,000 barrels and White Rose at 92,000 barrels.
But beyond there the prospects look shaky, unless there is a sudden turnaround in exploration fortunes, or companies respond positively to a call for bids covering 7.8 million acres in three areas.
The Hibernia reservoirs, estimated by the Canada-Newfoundland Offshore Petroleum Board at a combined 884 million barrels, 134 million barrels more than the Hibernia owners, have regulatory approval to increase to 220,000 barrels per day from 180,000 barrels.
The main Hibernia reservoir, according to the Canada-Newfoundland Offshore Petroleum Board, has 702 million barrels of recoverable crude and has been flowing since 1997.
But the 182-million-barrel Ben Nevis-Avalon reservoir is untapped. Whether it will be hinges on an evaluation by ExxonMobil, Hibernia’s major stakeholder, that expects to complete a revised development program by late 2005.
Petro-Canada-operated Terra Nova with 370 million barrels has been on stream for 16 months and has just received Canada-Newfoundland Offshore Petroleum Board permission to raise its rate to 150,000 barrels per day from 100,000 barrels and could get a further jump to 200,000 barrels. What after White Rose? Next in line is the 250-million-barrel White Rose project, owned by Husky Energy and Petro-Canada which is on track for a late 2005 start-up.
What comes after those three is a question that is fast gathering momentum, now that Chevron Canada Resources has shelved plans for its 700-million-barrel Hebron/Ben Nevis discovery, which it has decided is too geologically complex to be commercially viable.
The three producing fields are all in the Jeanne d’Arc Basin, where the Canada-Newfoundland Offshore Petroleum Board estimates reserve potential at 2.1 billion barrels of oil and 5.6 tcf of gas, of which 1.55 billion barrels of oil and 2.1 tcf of gas have been found.
In the meantime, the Canadian Association of Petroleum Producers is pressuring the Canadian government to tackle a “burdensome” regulatory process on the East Coast to ensure the region “remains competitive.”
The association pointed out that Nova Scotia approvals can take up to 90 days, compared with 40 days in the Gulf of Mexico.
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