As a perfect economic storm batters global markets one hatch of the Canadian ship of state remains wide open to boom times. Newfoundland and Labrador — known across Canada as The Rock — is experiencing accelerated private sector growth, most of it the result of offshore hydrocarbon industry investment.
“That particular part of our country seems to be a little bit insular right now with some of the pre-finance loading work that’s going on with Hebron and other things that are keeping things fairly buoyant in St. John’s, unlike some of the other regions of the country,” Ian Way, vice president of strategic planning and business development for ConocoPhillips Canada, said from his office in Calgary.
Oil production, exploration and several major development projects can be credited with buffering Newfoundland and Labrador, and to some extent Nova Scotia’s Halifax region, against the recession.
The Rock’s fields pumpingBy last January, The Rock announced that its three oil fields, Hibernia, Terra Nova and White Rose, combined, had pumped 1 billion barrels of crude since 1997 when Hibernia produced first oil for the province. The three discoveries provided its treasury with royalties exceeding $5 billion. In 2008 royalties and taxes accounted for 33 percent of provincial revenues.
Pointing out that Newfoundland and Labrador produces 50 percent of Canada’s light, sweet crude, Premier Danny Williams, in a news release, stated, “Since first oil from Hibernia we have established ourselves as a major player on the international energy scene.” The premier never mentioned Ottawa’s $288.2 million take from Hibernia last year as a result of soaring oil prices. The federal government owns 8.5 percent of Hibernia. Since 2002, that stake, managed by the Canada Hibernia Holding Co., has churned out $1.12 billion for Ottawa.
The corporation’s annual report states, “The near-term production outlook is for an increase as early as late 2009 compared to 2007-08 levels if the field extension (Hibernia South) is approved this year.” Having about another 30 years of life, Hibernia’s average daily production was 138,000 barrels in 2008. “The higher production levels will be maintained for several years before beginning a long-term decline in production,” states the report.
Gravity base structure to be builtOnce developed, the 700 million-barrel Hebron-Ben Nevis discovery should tighten the slack. By late 2013, more than 3,500 workers will begin at the Bull Arm offshore oil and gas fabrication facility building for the oil field a gravity base structure similar to yet smaller than Hibernia’s.
Situated 350 kilometers east of St. John’s and in the Jeanne d’Arc Basin, Hebron is scheduled to produce first oil before the end of 2017. Within two years of that date production should peak at 150,000 barrels daily. The field has a 20- to 25-year lifespan.
Hebron’s operator, ExxonMobil, has opened a project management office in St. John’s. Pre-front-end engineering and design (pre-FEED) is being orchestrated while a 20-member team coordinates and manages all procurement and contracting activities.
“We issued an expression of interest for our gravity base structure and front end engineering designs last week and in addition to that we’ve got our development plan,” Hebron business manager Lynn Ann Nicholosi said last summer. If Newfoundland and Labrador Natural Resources Minister Kathy Dunderdale is correct, most of the work — white collar and blue — will be done in the province.
“As a result of the world-class expertise developed at Hibernia, Terra Nova and White Rose, we are well positioned for the majority of the required fabrication and engineering work,” she said.
Modules for White RoseAnother big project fending off the economic downturn recently clued up at Bull Arm, on the western side of Newfoundland and Labrador’s Trinity Bay. White Rose oil field partners Husky Energy and Petro-Canada had huge yellow (the easiest color to spot underwater) modules assembled there primarily by a local Newfoundland and Labrador contractor called North Eastern Constructors Ltd. Some 300 of its hires during the past 12 months fabricated the modules for North Amethyst, a White Rose satellite field.
From his St. John’s office, Husky’s Atlantic Canada operations manager, Trevor Pritchard, in a distinctive Scottish accent said, “It’s a great milestone. We’ve had all those modules assembled at Bull Arm for our site integration testing, so it’s important for us to ensure the equipment is functional.” In sea depths approximating 120 meters, the WellServicer, a construction and diving support ship, using a humongous hydraulic hammer, will drive 10-tonne piles (hollow carbon steel pipes) 13 meters through the bottom of a 10-meter-deep glory hole designed to protect the project from seafloor-scoring icebergs.
“It just drives the pile right down,” said Gordon Phillips, North Amethyst project manager for Husky. Piles hold the modules in place. A subsea flowline system is being connected to the modules and wells. It will send North Amethyst oil to the White Rose floating production, storage and offloading (FPSO) vessel. Pritchard said, “We have two drill centres for production, the southern drill centre and the central drill centre. Any production that comes from North Amethyst will come on the current flowlines of the southern drill centre.”
The project, absorbing $1.8 billion and destined to pump crude by year-end or early 2010, is the first of three such oil fields to be developed for the overall expansion of White Rose. They contain about 214 million barrels of crude. North Amethyst has 71 million. Like Hibernia, Hebron and Terra Nova, White Rose resides in the Jeanne d’Arc basin and is reaching maturity.
Hibernia expansion expectedComplementing that development, Hibernia, a discovery containing more than 1.9 billion barrels of recoverable crude and also located in the Jeanne d’Arc, is expected to be expanded within the next two years by developing Hibernia South. The satellite field holds more than 223 million barrels of light, sweet crude and can pump for a period of 10 to15 years.
“This development again builds on existing infrastructure of another mature field,” said Dunderdale. Project cost estimate is $2 billion. “Negotiations are continuing between the province and the Hibernia proponents, led by ExxonMobil, to reach an agreement on this development,” she said.
Her government, meanwhile, has transformed Newfoundland and Labrador Hydro into a multifaceted energy firm, dubbing it Nalcor Energy. The company, about a year ago, took control of Bull Arm and its business activities. Nalcor is involved in developing wind energy in the province too. It has 4.9 percent equity in Hebron, a 5 percent share of White Rose’s satellite fields and aspirations of turning one of North America’s biggest watersheds, the Lower Churchill River system in western Labrador, into a mega-hydroelectric project possibly supplying Ontario and New England. The venture’s construction budget could reach $10 billion.
Deep Panuke sanctionedAfter a roller coaster ride full of on-again and off-again development deals the $700 million Deep Panuke offshore natural gas project, 175 kilometers from the shores of Goldboro, Nova Scotia has finally been sanctioned for construction. Major contracts are being awarded and Canada’s National Energy Board approved Deep Panuke’s pipeline route.
An offshore pipeline is being installed this year so the venture can in 2010 commence supplying markets from its store of 900 billion cubic feet of gas. The project includes the drilling of an acid gas injection well this summer plus re-entry and completion of four existing exploration wells.
Repsol will buy all of Deep Panuke’s gas output. EnCana has agreed to sell it 300 million cubic feet per day until product is exhausted. Repsol owns 75 percent of the Canaport LNG import and re-gasification terminal, which has almost been constructed in St. John, New Brunswick. The plant will export into the U.S. Northeast.
“Our target is to get a 20-percent share of the Northeast market,” Repsol spokesman Kristian Rix said.
Harvest upgrading complexIn other Eastern Canadian downstream happenings, Calgary-based Harvest Energy continues upgrading its petrochemical complex near Come by Chance, a fishing community at the mouth of Placentia Bay in Newfoundland and Labrador. Its president and CEO, John Zahary, said, “As we go forward we’ve got about $300 million worth of projects that we can do over the course of time.” Harvest Energy plans to inject $2 billion into expanding the facility when the economy picks up.
“Further out, we’ve got another project, which is a very large project, about $2 billion,” he said. “It will get done. For the time being that project is on hold until the global economy is such that it’s something we can proceed with.”
No more than 100 kilometers from that downstream venture, there is a downside to Newfoundland and Labrador’s oil and gas business and Mark Turner refuses to downplay it. Until last summer, Newfoundland LNG Ltd. seemed sure about erecting a liquefied natural gas terminal. Turner, who is company president, said the recession crippled the $1.5 billion project. In preparation mode since 2001, Newfoundland LNG received federal environmental approval last fall for the three marine jetties and eight storage tanks it proposes to build at Grassy Point, Placentia Bay. The province had already come onboard, environmentally. Development was expected, but financing fell through. Instead of dead, the venture is being delayed, according to Turner. “We’re after investing $10 million; we’re not just going to throw it away,” he said. “We’ve been talking to our clients and they want us to hold on until they come back.” Newfoundland LNG needs $500 million to stay afloat and may apply for federal bridge financing.
The second of this two-part series will deal with the diversification and growth of the petroleum industry’s service and supply sector in Atlantic Canada while examining the region’s rapidly increasing exploration play.