Oilweek - East Coast Supplement November 2011 by JWN | Trusted energy intelligence

EAST COAST SUPPLEMENT :: NOVEMBER 2011

Biding time Encana pushes first gas from Deep Panuke further out to Q4/2011

Island in the sun Quebec-based Junex hopes for bright days ahead as it probes Anticosti Island’s shale oil potential

Calm waters Although lacking the frenzy of substantial new exploration, Newfoundland’s offshore continues as a stabilizing influence on the province’s economy

FOCUSING ON KEY ISSUES AFFECTING OIL & GAS ACTIVITY IN THE REGION

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tab l e of con t e n t s

Photo: Encana Corp.

Editor’s note 5 infrastructure

East Coast Infrastructure 6 A primer on what’s what N ova Scotia

Biding time 8 Encana pushes first gas from Deep Panuke further out to Q4/2011 By R.P. Stastny

Anticosti Island

Island in the sun 12 Quebec-based Junex hopes for bright days ahead as it probes Anticosti Island’s shale oil potential By Wes Reid

Newfoundland

Calm waters 15 Although lacking the frenzy of substantial new exploration, Newfoundland’s offshore continues as a stabilizing influence on the province’s economy By Wes Reid

Advertisers’ index 18

On the cover: Encana is close to commissioning its Deep Panuke project on the Scotian Shelf.

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editor’s note

EAST COAST SUPPLEMENT :: NOVEMBER 2011

President & CEO Bill Whitelaw | bwhitelaw@junewarren-nickles.com

Interim Publisher Chaz Osburn | cosburn@junewarren-nickles.com

Editorial Editor Dale Lunan | dlunan@junewarren-nickles.com Staff Writer R.P. Stastny | pstastny@junewarren-nickles.com Editorial Assistance Manager Samantha Kapler | skapler@junewarren-nickles.com Editorial Assistance Laura Blackwood, Brandi Haugen proofing@junewarren-nickles.com

Contributors Wes Reid

creative Production, Pre-Press, and Print Manager Michael Gaffney | mgaffney@junewarren-nickles.com Senior Publications Manager Audrey Sprinkle | asprinkle@junewarren-nickles.com Art Director Ken Bessie | kbessie@junewarren-nickles.com Creative Services Manager Tamara Polloway-Webb | tpwebb@junewarren-nickles.com Graphic Designer Janelle Johnson | jjohnson@junewarren-nickles.com

sales Director of Sales Rob Pentney | rpentney@junewarren-nickles.com Sales Manager — Advertising Maurya Sokolon | msokolon@junewarren-nickles.com Senior Account Executive Diana Signorile Sales Nick Drinkwater, Ellen Fraser, Michael Goodwin, Rhonda Helmeczi, Nicole Kiefuik, Jeff LeHoux, David Ng, Sheri Starko For advertising inquires: adrequests@junewarren-nickles.com Ad Traffic Coordinator — Magazines Denise MacKay | atc@junewarren-nickles.com

marketing Marketing/Trade Show Coordinator Jeannine Dryden | jdryden@junewarren-nickles.com Marketing Designer Corinne McKetiak | cmcketiak@junewarren-nickles.com

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Fuelling the engine Oil and gas is the engine of growth on the East Coast, but new discoveries are needed to keep the engine tuned There’s little doubt that as the offshore goes, so goes Atlantic Canada. Oil in Newfoundland, natural gas in Nova Scotia, perhaps one day shale gas in New Brunswick: oil and gas have become key cogs in the economy of the East Coast. Ever since the cod fishery was shut down two decades ago, the economy of Newfoundland has thrived on the riches brought to it by the oil industry. Hibernia was first off the mark, in 1997, followed five years later by Terra Nova, in 2002, and White Rose, in 2005. The taxes and royalties brought in by oil allowed the Rock to get off the public dole: in 2008, it announced that it was no longer a “have-not” province in Confederation, a status signalled by the fact it would not qualify that year for equalization payments for the first time in its history. Nova Scotia hopes one day to achieve the same nirvana. Its waters were actually home to Canada’s first commercial offshore oil extraction, at Cohasset-Panuke, which produced about 45 million barrels of oil between 1992 and 1999, but since then, the province’s energy riches have been derived from the Sable Offshore Energy Project (SOEP), which came on stream in 1999 and now delivers about 300 million cubic feet per day of natural gas and 14,000 barrels a day of natural gas liquids. New Brunswick has had a tiny natural gas industry for a few years now, thanks mostly to Corridor Resources Inc. and its McCully field. Now, shale gas has caught the fancy of a few developers, but the environmentalists are urging the government to halt fracking, a move which would stop the infant shale gas business dead in its tracks. What has mostly held the East Coast oil and gas industry back is that, since Hibernia was launched, the sector has essentially lived in the moment. The project of the day drove activity, and for most of the last 15 years, exploration for new reserves has been spotty at best, a situation not helped by the dearth of discoveries, especially on the Scotian Slope and Shelf, where SOEP has been the alpha dog since it was commissioned. All that may be changing now. Development of known fields is continuing, certainly. Offshore Nova Scotia, Encana Corporation’s Deep Panuke gas project is slated to come on stream later this year. And on the Grand Banks, ExxonMobil and its partners are moving forward with their Hebron heavy oil field. First oil is expected in 2017. But the long-term survival of the East Coast oil and gas industry is dependent on landing new catches, and on this front, the industry is at least making some strides. Back in the spring of 2009, StatoilHydro Canada recorded an oil discovery at its Mizzen prospect in the deep waters of the Flemish Pass, and is back there now drilling a follow-up well. Last summer, Chevron Canada and its partners drilled the closely watched Lona-O55 well in 2,600 metres of water even as BP plc struggled to control its Macondo disaster in the Gulf of Mexico. Husky Energy Inc. and Suncor Energy Inc. have also been poking around their Glenwood and Ballicatter prospects lately, and while no firm plans for additional drilling there have been announced, at least both companies have shown some interest. In the end, it is this kind of interest—mixed in with a successful well here and there—that will sustain the East Coast oil and gas industry into the future. — Dale Lunan

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infrastructure

East Coast Infrastructure

Labrador Sea

Labrador

Newfoundland

Gulf of St. Lawrence

Hibernia

Charlottetown

White Rose

illustration: ExxonMobil

Quebec

St. John’s

Hebron/ Ben Nevis Terra Nova

Fredericton Quebec City

Halifax

Sable Deep Panuke

Ottawa

Oilfields Gas Fields The Hebron field offshore Newfoundland will be developed with a gravity-based structure.

Active Developments HIBERNIA Atlantic Ocean Status: In production Approved production rate: 220,000 barrels per day 2010 production: 154,350 barrels per day First oil: Nov. 17, 1997 Field location: Grand Banks, 315 kilometres east-southeast of St. John’s, N.L. Discovery date: 1979 Operator: Hibernia Management and Development Company Ltd. Project participants: ExxonMobil Canada Properties (33.125 per cent) Chevron Canada Resources (28.875 per cent) Petro-Canada Hibernia Partnership (20 per cent) Canada Hibernia Holding Corp. (8.5 per cent) Murphy Atlantic Offshore Oil (6.5 per cent) StatoilHydro Canada Ltd. (5 per cent) Water depth: 80 metres (262 feet) Discovered recoverable reserves: Oil—1.4 billion barrels Natural gas—1.7 trillion cubic feet Nassau BAHAMAS Natural gas liquids—202 million barrels Production life: 20 years (approximate) beyond 2020 Mode of development: Gravity Based-Structure (GBS) supporting drilling, production and accommodation facilities Storage capacity: 1.3 million barrels - Subsea export line to two offshore loading systems - Two, 127,000 dwt shuttle tankers - Onshore transshipment facility

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Expansion plans: Hibernia Southern Extension was approved by regulators in October 2010, tapping another 223 million barrels of new reserves. Development will take place from the existing Hibernia platform. TERRA NOVA Status: In operation Approved production rate: 150,000 barrels per day 2010 production: 68,325 barrels per day First oil: January 2002 Field location: Grand Banks, 350 kilometres east-southeast of St. John’s, N.L. Discovery date: 1984 Operator: Suncor Energy Inc. Project participants: Suncor Energy Inc. (37.675 per cent) ExxonMobil Canada Properties (19 per cent) StatoilHydro Canada Ltd. (15 per cent) Husky Energy Inc. (13 per cent) Murphy Oil Company Ltd. (10.475 per cent) Mosbacher Operating Ltd. (3.85 per cent) Chevron Canada Resources (1 per cent) Water depth: 90–100 metres (295–328 feet) Discovered recoverable reserves: Oil—354 million barrels Production life: 20 years from first oil Mode of development: Steel FPSO (floating production storage and offloading) vessel - Design storage capacity: 960,000 barrels - Production facility capacity: 180,000 barrels per day

infrastructure

Photo: ExxonMobil

WHITE ROSE Status: In operation Approved production rate: 137,000 barrels per day 2010 production: 42,925 barrels per day (White Rose) 15,615 barrels per day (North Amethyst) First oil: November 2005 Field location: Grand Banks, 350 kilometres east of St. John’s, N.L. Discovery date: 1984 Operator: Husky Energy Inc. Project participants: Husky Energy Inc. (72.5 per cent) Suncor Energy Inc. (27.5 per cent) Water depth: 125 metres (410 feet) Discovered recoverable reserves: Oil—229 million barrels, proved plus probable Natural gas liquids—96 million barrels, proved plus probable Natural gas—2.7 tcf (estimated resource)

Inside the Sable Offshore Energy Project’s control room.

SABLE OFFSHORE ENERGY PROJECT Status: In production First gas: Dec. 31, 1999 Field location: Scotian Shelf, 200 kilometres off eastern coast of Nova Scotia 2010 production: Natural gas: 300 million cubic feet per day; Natural gas liquids: 14,000 barrels per day Producing fields: Thebaud—1999 Venture—1999 North Triumph—1999 Alma—2003 South Venture—2004 Discovery date: Venture—1979 Thebaud—1972 Operator: ExxonMobil Corporation Project participants: ExxonMobil Corporation (50.8 per cent) Shell Canada Energy (31.3 per cent) Imperial Oil Resources Limited (9 per cent) Pengrowth Corporation (8.4 per cent) Mosbacher Operating Ltd. (0.5 per cent) Water depth: 20–80 metres (65.6–262 feet)

Mode of development: - Central processing platform at Thebaud, with satellite platforms at Venture, North Triumph, Alma and South Venture - Dedicated accommodation platform at Thebaud - 200 kilometres of interfield flowlines - 200 kilometres of gathering lines from Thebaud to the onshore gas plant at Goldboro, N.S. - Natural gas liquids line from gas plant at Goldboro to fractionation plant at Point Tupper, N.S. Projects Under Development DEEP PANUKE Status: Under development First gas expected: Fourth quarter 2011 Field location: 250 kilometres southeast of Halifax, N.S. Operator: Encana Corporation Water depth: 45 metres Discovered: 2000 Estimated recoverable resources: 400–900 billion cubic feet of natural gas; mean recoverable of 630 billion cubic feet of sales gas Production life: 8.5–17 years (average of 13 years) Project schedule: Encana’s Board of Directors sanctioned Deep Panuke for development in October 2007. In November 2007, Encana announced that it had entered into an agreement with Single Buoy Moorings Inc. (SBM) for the provision and operation of the Deep Panuke production field centre. Regulatory applications for Deep Panuke were filed in 2006, with approvals granted in 2007. Mode of development: Offshore production and processing. Subsea pipeline transportation to landfall in Nova Scotia. Production rate: Design capacity of 300 million cubic feet per day HEBRON Status: Pre-development The Hebron partners and the Government of Newfoundland and Labrador signed a development agreement in August 2008. First oil is currently projected in 2017. Field location: 350 kilometres offshore Newfoundland and Labrador Operator: ExxonMobil Oil Canada Properties Project participants: ExxonMobil Oil Canada Properties (36 per cent) Chevron Canada Limited (26.7 per cent) Petro-Canada (22.7 per cent) StatoilHydro Canada Ltd. (9.7 per cent) Nalcor Energy (4.9 per cent) Water depth: 92 metres (302 feet) Discovery: 1981 Estimated recoverable reserves: 400 million–700 million barrels Peak production: 150,000–170,000 barrels per day Production life: 20–25 years (est.)

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N ova Scotia

Biding

time

Encana pushes first gas from Deep Panuke further out to Q4/2011 By R.P. Stastny

Encana Corporation expects to be producing gas from its Deep Panuke project offshore Nova Scotia by the end of this year.

This summer, Encana Corporation’s Deep Panuke offshore production platform made a 50-day Atlantic crossing from Abu Dhabi to Mulgrave, N.S. Several days later, it was barged out to the field site for connection to four production wells 250 kilometres southeast of Halifax, in preparation for first gas. Then in September, Encana announced a delay in the start of production, already a second rescheduling from Encana’s original plan for first gas in the fourth quarter of 2010. “There are differing views on how the speed of the project management is to progress, but we’re in discussions with SBM [Single Buoy Moorings Inc., which owns and is leasing the platform to Encana for eight years],” Encana spokesman Alan Boras says. He offers few specifics about the delay or its expected duration. (This may be partly because Encana is in a legal dispute with SBM over additional compensation for the production platform.)

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Following Encana’s delay announcement, one media source had Sebastiaan de Ronde Bresser of SBM saying the completion of the platform is taking longer than expected and that SBM’s portion of the preparatory work should be done by the second quarter of 2012. Encana’s president and chief executive officer, Randy Eresman, however, told analysts and investors at the Barclay’s Capital CEO Energy-Power Conference in New York City in September that Deep Panuke would be on stream by the end of the 2011. No hurry Encana used the summer months to complete offshore work at Deep Panuke, such as rock placement, which saw about 70,000 tonnes of rock placed on the gas export pipeline, flowlines and structures offshore to provide stability. The umbilicals—the control conduits for remote operation of the

N ova Scotia

Photo: Encana Corp.

wells at Deep Panuke—were installed alongside the flowlines that will transport natural gas. If nothing else, there’s plenty of time to get this work done right now. Observers suggest Encana may not even be eager to bring Deep Panuke on in this low gas price environment. Asked about the economics of Deep Panuke, Boras says it expects profitable production “on a go-forward basis, but the challenge of course is current gas prices.” In fact only a few dry gas plays in North America are economic these days on a full-cycle basis—and a high-tech, complex offshore project probably wouldn’t be one of them. Encana’s financial situation also provides an interesting backdrop for Deep Panuke. It is curbing near-term growth and strengthening its balance sheet. At the Barclay’s Capital conference, Eresman explained the company’s current strategy.

“During this period of cyclically low gas prices, we allowed our leverage over the short term to increase,” he said. “This was done to maintain a relatively loaded development program, allow us to take advantage of promising oil and liquids-rich opportunities and grow…our gas production. As we’re now nearing the upper limit of our…debt-to-debtadjusted cash flow range, our intention is to pragmatically reduce our debt level.” Since splitting off most of its crude oil and oilsands assets to Cenovus Energy Inc. in 2009, Encana has become essentially a natural gas pure-play company and tied its fortunes to an extended spell of low gas prices. In Encana’s effort to “restore financial flexibility and strength by year-end,” the company has agreed to sell a portion of its Piceance midstream gas assets in Colorado for about US$590 million. It has “very well-advanced divestiture packages” for midstream assets in the Deep Basin of Alberta

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N ova Scotia

Photo: ExxonMobil

The Thebaud complex, part of the Sable Offshore Energy Project, has been producing natural gas off Nova Scotia since 1999.

and British Columbia, and for interests in the Cabin gas plant in northeastern B.C. “We also have upstream divestiture processes under way on a portion of our Jean Marie property in northeastern B.C., and on our Barnett shale play in northern Texas,” Eresman said. Proceeds of the latter sales will supplement the company’s cash flow in the current gas price environment, and provide flexibility going into 2012 and 2013. Observers “Things haven’t exactly gone Encana’s way in the last year,” says Ed Kallio, Ziff Energy Group’s director, natural gas consulting. “It’s putting a lot of assets up for sale. It had that deal with the Chinese company fall through [a joint venture partnership proposal to develop natural gas in northeastern B.C.], so that certainly doesn’t make them want to go after higher-cost gas prospects such as Deep Panuke in the face of fairly low gas prices.” In a Ziff Energy 2010 report cataloguing the full-cycle costs of North America’s gas plays, the best economics are in liquids-rich and shale gas proximate to large U.S. consumer bases, the worst in Canadian coalbed methane and Foothills gas. While it doesn’t estimate the production costs of Deep Panuke, Kallio expects it would come in above the Canadian average full-cycle cost of about $6 per

E A ST CO A ST O I L & G A S

thousand cubic feet—probably more towards the upper end of the cost curve. As for Eresman’s “period of cyclically low gas prices,” some observers, and even some producers, see current gas prices more as the new normal or at least as a low point in a much longer, slower cycle. “Production costs have really dropped for the whole industry because of technology,” Kallio says. “And, overall, gas production has grown.” One non-economic driver adding to gas supplies is big shale companies buying large land positions in major plays. To keep those leases, they have to produce. So a couple hundred rigs were drilling gas in the United States last year and this year just to hold lands, Kallio says, even though their full-cycle costs were above market prices. “We’ve seen an explosion in drilling in the Haynesville, which you wouldn’t otherwise have seen,” he notes. “In Eagle Ford we might have seen high activity levels anyway because of the liquids. And some areas of the Marcellus would have kept going because of the economics of being so close to major consuming centres.” The hold by production (HBP) factor may weaken by 2012, so gas production may become more rooted in fundamentally economic drivers and prices may strengthen, which would bode well for Encana if it’s waiting for stronger

N ova Scotia

gas process and a stronger balance sheet to bring on Deep Panuke. But that scenario may not pan out, since U.S. gas producers have still been adding to their land positions, so the HBP factor may only shift to other areas. On the demand side, natural gas should eventually make big gains as natural gas–fired power generation gains momentum. According to Ziff’s forecast, the current 21 billion cubic feet per day will grow to 30 billion cubic feet per day by 2020. Another two billion cubic feet per day will be needed by the oilsands over the next 10 years or so, which currently consume one billion cubic feet per day, and efforts to close the natural gas/oil price gap by developing liquefied natural gas export capability and/or natural gas liquefaction opportunities will also drive demand and prices upward. But all of this is still a decade away. Which is to say, if Encana doesn’t appear eager to launch Deep Panuke production, who can blame it, considering the challenging gas market, the technical complexity of bringing on a $1-billion offshore platform, its legal wrangling with SBM, and Encana’s near-term financial rebalancing act. This delay only begs more questions: while Encana searches for joint venture partners for its northeastern B.C. gas, is it also looking for a Deep Panuke partner; or, given its various divestiture packages, is Deep Panuke being readied for the auction block? The one thing that is certain is that Encana won’t be providing much detail on any of this just yet.

About Panuke • Encana discovered the Deep Panuke gas reservoir in 1998. Several delineation wells were drilled. Four wells were suspended for potential future re-entry. The remaining wells were abandoned. • Encana’s Deep Panuke project was officially approved for development by Encana’s Board of Directors in October 2007, when gas prices were tracking oil prices to record highs. • The design capacity of the project is 300 million cubic feet per day. Encana estimates recoverable sales of 632 billion cubic feet over 13 years. • Capital construction costs for Deep Panuke are estimated at $800 million with average annual production phase expenditures of approximately $150 million. • The production platform is situated in a water depth of about 45 metres over four production wells with one disposal well for hydrogen sulphide and CO2 . • Encana initially planned first gas for Q4/2010, which it delayed to the first half of 2011, then extended the delay to Q4/2011.

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Anticosti Island Illustration: Junex

Quebec-based Junex Inc. has a significant land position in the Macasty shale fairway on Anticosti Island, in the Gulf of St. Lawrence.

Island in the sun Quebec-based Junex hopes for bright days ahead as it probes Anticosti Island’s shale oil potential By Wes Reid

Junex Inc. comes well-prepared. Rather than pay premium rates and wait lengthy periods for often hard-to-get drilling rigs, the Quebec-based junior explorer—unlike most, if not all, of its competitors in eastern Canada—built its own to explore properties on Anticosti Island and in Quebec. “We have a new rig; we just built it last fall,” says the company’s chief operating officer, Peter Dorrins. “We’ve only drilled one hole with it. What’s nice about it is that it’s got about a 2,000-metre [drilling] capacity, which is pretty good, and it’s built according to the latest American Petroleum Institute specifications.”

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Junex designed the unit for Quebec’s roads that are, in the company’s estimation, less suited for rig transport than are roads in Alberta, an understandable situation since Alberta is a major petroleum producer internationally whereas Quebec has yet to even see oil or gas development. “The drill rig breaks down in small-enough modules so that it can move easily on roads in Quebec,” Dorrins says. “I know other companies, when they’ve been bringing rigs out from western Canada, have had some headaches trying to move them. What you can move in Alberta, our roads can’t handle here.”

Anticosti Island

”Anticosti is a pretty big place, but sparsely populated. This can create some challenges, one of them being that in Quebec, the average person understands hydro really well, but when it comes to petroleum and natural gas play, there’s no real experience with it.” — Peter Dorrins, chief operating officer, Junex Inc.

Possessing a drill rig or two can also provide a competitive edge, decrease business complications and reduce stress, he adds. “We have a couple of drilling rigs and the reason we have them is that for us being here in eastern Canada, where there’s not much oilfield equipment around, we decided that it makes business a lot easier, more streamlined, because it gives us timely access and, at the same time, costs us less.” The machine drills directionally, has a top drive and can carry different lengths of drill pipe. “It’s what we call a double rig…so it can have two pieces of drill pipe, nine metres long,” says Dorrins. “We have a top drive on it and we typically drill directionally with it.” The rig will come in handy as Junex focuses on a shale oil exploration program of a geological structure on Anticosti Island known as the Macasty shale formation. Lying near the mouth of the St. Lawrence River, the island has approximately 120 residents, and is the 90th largest in the world. “Anticosti is a pretty big place, but sparsely populated, about a hundred and twenty people year-round,” Dorrins says. “This can create some challenges, one of them being that in Quebec, the average person understands hydro really well, but when it comes to petroleum and natural gas play, there’s no real experience with it.” Junex owns 100 per cent of the Macasty prospect—the licence covers more than 233,000 acres of land—and has a well there called Arco Anticosti No. 1. It also holds four other hydrocarbon exploration licences for Anticosti. “We’ve had some exploration licences on Anticosti Island for, oh, a few years and we’ve been kinda quietly working, doing our research,” Dorrins says. “Where we have our acreage now, there was one well drilled in the ‘70s by Atlantic Richfield,” a stratigraphic test drilled to a depth of 3,850 metres. “It’s the deepest well that’s been drilled on the island to date and it was basically a stratigraphic test, meaning they just drilled it down with very little technical reason other

than to find out what was there; the porosity of the rocks and whether there were hydrocarbons in those rocks.” Arco’s Macasty shale runs between 2,399 metres and 2,487 metres deep where, in the words of a news release Junex circulated in September, “it has attained its full thermal maturity for oil generation and is in the late oil window to early condensate—wet gas window of thermal maturity.” The majority of the Macasty shale on Junex acreage is at depths ranging between 800 metres and 2,200 metres. Its porosity averages 6.3 per cent, which, according to the news release, “compares favourably with other North American shale resource plays and which may be a positive indicator of potential resources initially in place.” After samples collected from Arco Anticosti drill cuttings were analyzed last summer, Junex management felt the well could be in a “tight, oil-to-liquid hydrocarbon-rich” shale formation. Dorrins is eager to note that Quebec is incorrectly portrayed as a province potentially rich in only shale gas. “Everybody that’s been active in Quebec [hydrocarbon activity] the last four or five years has been labelled as being shale gas explorers, but Junex has other acreage too,” Dorrins says. “On the Gaspé Peninsula in eastern Quebec, we have some conventional oil type plays that we were looking at. Anticosti is one of those as well. It seems more of an oil play than a shale gas play.” Quebec has very limited natural gas infrastructure and Anticosti Island is a long way away from the closest system (located in New Brunswick) capable of piping to market commercial quantities of natural gas, if it were discovered there. “Due to the challenges we’re facing here, we’re trying to move into areas that are more on the oil side than on the gas side,” says Dorrins. “And Anticosti fits that bill, as does the Gaspé Peninsula.” Hamstrung by distance and an encompassing ocean, Junex, having taken its sights off gas exploration, has hopes of sinking two wells at Anticosti next year. “It’s possible that if we’re out there on Anticosti next year—considering we’re moving out to an island and that’s

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Anticosti Island

”We are very encouraged by these positive lab results and are quickly advancing to the next step of our shale oil program in Anticosti.” — Jean-Yves Lavoie, president, Junex Inc.

a logistical challenge and everything else—we would look hard at possibly drilling a second exploration well there,” Dorrins says. An airborne gravity geophysics survey was completed last summer to identify major structural elements. This allows Junex to progress with a multi-year Macasty shale oil exploration program that could include any or all of the following work: seismic surveys, re-entry into the Arco well, drilling of stratigraphic test wells and other exploration activity in 2012 and beyond. “We are very encouraged by these positive lab results and are quickly advancing to the next step of our shale oil

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program in Anticosti,” Junex president and chief executive officer Jean-Yves Lavoie said last September. Junex also has exploration rights to approximately 5.2 million acres of land located in Quebec’s Appalachian Basin and the Utica Shale Basin in the St. Lawrence Lowlands. “These strategic lands form part of our petroleum/ liquids–rich portfolio that also includes our oil-rich landholdings at Galt and Haldimand on the Gaspé Peninsula,” said Lavoie. “Exploration for these oil properties will be Junex’s focus for the next few years as our activities have been slowed down in the Utica Shale Basin.” Junex has working capital of more than $17 million as well as positive cash flows from its natural brine and drilling services operations. Building more rigs may not be in the company’s stars, but Dorrins thinks there is potential for a niche market to eventually emerge on the East Coast, especially if discoveries are made and hydrocarbon field developments occur. “There could be a small market here that might grow as long as the region becomes more active, and I believe it will,” Dorrins said from company headquarters in Quebec City. “I see a lot of hydrocarbon industry promise in this region.” In the meantime, Junex is not averse to leasing the double rig to other companies. “You never know, if our neighbours on our adjoining acreage are interested in using the rig, then that’s a possibility,” Dorrins says.

Newfoundland

The semi-submersible Henry Goodrich, on its way to drill the Mizzen F-09 well offshore Newfoundland for Statoil Canada Ltd.

Calm waters Although lacking the frenzy of substantial new exploration, Newfoundland’s offshore continues as a stabilizing influence on the province’s economy

Photo: Statoil Canada

By Wes Reid

Rumblings of another deep recession—or in the words of former prime minister Paul Martin, a continuation of the Great Contraction—along with hurricanes, rogue icebergs by the bay load and politicians demanding hydrocarbon exploration moratoria, have all failed to dent the Rock’s bustling offshore hydrocarbon sector. Industry activities in the rest of eastern Canada may pale in comparison, but they do appear stable. So it’s steady as she goes for the region’s petroleum play. Ships and helicopters transport, usually with uninterrupted regularity, personnel and supplies to the Rock’s offshore oilfields and, to a lesser extent, gas field activities off Nova Scotia. Newfoundland and Labrador’s three producing discoveries, Hibernia, Terra Nova and White Rose, and its mining ventures have significantly heated the provincial economy. “I hope that one day Quebec’s oil and gas potential takes off the way Newfoundland’s has,” says Peter Dorrins, chief operating officer of Junex Inc., a junior exploration company with several prospects throughout Quebec, including Anticosti Island. “That province must be an exciting place to be if you’re involved in hydrocarbon play there right now.”

That might be so, but many rural pockets of the Rock are suffering from high levels of unemployment, primarily due to commerce decline. An area reaching from the Eastern Avalon Peninsula to Trinity Bay is, however, experiencing exceptional economic rejuvenation. This is creating a host of business, job and career opportunities while spiking the cost of living, in the manner of changing the word “house” to “manor.” The salt box abode is once again in vogue as sentimental Rocksters, flush with petro-dollars, buy and build residences resembling the houses in which they were raised. The similarity is restricted to design because, when it comes to Newfoundlanders’ new-found purchasing power, it appears size does matter. While the United States wonders if it is waking from an economic nightmare, a commercial and residential building boom on the Rock bespeaks its prowess as an oil producer internationally on the rise; a dream come true for the province. “My son works in the oil industry here,” says 67-year-old Clarence Petten, a carpenter raised and living in Conception Bay. “He’s doing really well and the company is sending

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Newfoundland

”In order to sustain...activity well into the future...industry has to find more oil and gas or the fear is exploration activity may curtail.” — Paul Barnes, Atlantic Canada manager, Canadian Association of Petroleum Producers him outside the province now to work on one of their other rigs. By the sound of things, there’s going to be lots more work like that in the province.” If the Newfoundland and Labrador Employers’ Council is correct, about 77,000 jobs will be created over the next eight years in the province, the majority of them generated directly and indirectly by petroleum and mineral activity. “There was nothing that was a surprise there to me, but some of the employers that are in the room probably were surprised by some of the statistics. And they’re quite significant—77,000 job opportunities between now and 2020, that’s a big thing,” Richard Alexander, the council’s executive director, said during an employment summit the organization held in St. John’s in September. Right now, though, hiring demand for petroleum sector areas such as exploration is subdued. “Companies continue to drill one or two wells per year and that pace will continue into the future,” says Paul Barnes, Atlantic Canada manager for the Canadian Association of Petroleum Producers (CAPP). “This drilling pace has been the norm in the last several years. In order to sustain that activity well into the future, however, industry has to find more oil and gas or the fear is exploration activity may curtail.” Contrasted with East Coast offshore exploration activity, the Rock’s oil extraction rates and petroleum industry job stats are impressive. By 2009, the province’s hydrocarbon sector, having reached 12 years of production maturity, pumped one billion barrels of oil. Last year, the Hibernia oilfield alone churned out 56.3 million barrels of light, sweet crude. The project requires 1,090 employees to see that its 1.4 billion barrels of recoverable oil are fully tapped. Ottawa, with an 8.5 per cent ownership stake in the venture through the federal Crown corporation Canada Hibernia Holding Corporation (CHHC), has collected about $916 million from the project since it started making net profits in February 2009. CHHC, though, began paying dividends to the federal government in 2003, the year it repaid Ottawa’s 8.5 per cent investment, an amount equalling $431 million. In the process, the feds have raked in $2.3 billion in combined dividends and net profits since Hibernia began producing oil in 1997.

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At a cost of $1.7 billion, work on the Hibernia South Extension (HSE) continues. The first of at least four production wells was spudded in March, putting the HSE development plan ahead of schedule. Drilling and subsea development activities will occur throughout 2012 and 2013, and once water injection is established, HSE completion could occur in 2014. Another of Newfoundland and Labrador’s discoveries is also undergoing major expansion work. White Rose continues to see good production while its operator, Husky Energy Inc., focuses on developing the oilfield’s satellite extension discoveries, North Amethyst and West White Rose. More than 169 million barrels of crude have been drawn from White Rose since first oil in November 2005. The oilfield’s floating, production, storage and offloading (FPSO) vessel, the SeaRose, completed a five-year major certification in the fall of 2010 and last July underwent a two-day maintenance turnaround. Subsea flowlines are used to bring oil from the satellite fields to SeaRose. North Amethyst achieved first production in May 2010, marking the first North American implementation of the practice of using subsea flowlines tied back to a rig to produce oil from satellite fields. A two-well pilot project at West White Rose is providing information on the reservoir as Husky finalizes a full development plan for the field. The first pilot well commenced producing on September 5, while work continues on the second well, a supporting water injector. Husky is studying the feasibility of building—via expansion of existing infrastructure—a fixed structure wellhead platform for future development at White Rose. “The concept under consideration would have a concrete gravity structure similar to Hibernia and the proposed Hebron gravity-based structure (GBS), but, unlike those facilities, it would not have oil storage or production capability. Oil would still be produced via the SeaRose FPSO,” Husky spokeswoman Colleen McConnell says. Scheduling for development of the $8.3-billion HebronBen Nevis heavy oil field—located in the Jeanne d’Arc Basin with the province’s other producing oilfields— remains on track. The Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) is carrying out an independent

Newfoundland

review of the project. Last July, the board made Miller Ayre, a former publisher of the St. John’s Telegram, the review’s commissioner. The review will deal with the project’s fields: Hebron, Ben Nevis and West Ben Nevis. Combined, they hold more than 700 million barrels of oil. To exploit Hebron, operator ExxonMobil Corporation will have a GBS built at Bull Arm, an offshore hydrocarbon industry fabrication centre situated on Trinity Bay where the Hibernia GBS was constructed during the 1990s. The Hebron platform and its topsides, once they commence functioning in 2017, are expected to pump 150,000 barrels of crude per day from the field, a rate that could rise to 180,000 barrels per day. Chances are petroleum sector megaprojects in Newfoundland and Labrador won’t end with the development of Hebron-Ben Nevis. In late July, Statoil returned once again to the Flemish Pass and began a delineation program on its deepwater Mizzen prospect, further evaluating its O-16 discovery well, drilled two years ago. To facilitate the delineation program, Statoil has again joined with Suncor Energy Inc. and Husky to share the use of the semi-submersible Henry Goodrich, a rig capable of operating in waters up to 1,500 metres deep. The transaction allows the firms to pursue exploration drilling and development programs much more

cost-effectively than if they were to separately lease their own rigs. “By their very nature, rig-sharing agreements encourage increased partnerships and cooperation between companies involved in the oil and gas industry while supporting continued exploration, a crucial step to finding new discoveries,” Newfoundland and Labrador Natural Resources Minister Shawn Skinner says. The first arrangement ensured that Suncor completed drilling its Ballicatters exploration well on the Grand Banks. The agreement also led to Statoil’s discovery at Mizzen O-16, in 1,100 metres of water about 500 kilometres east of St. John’s. That project took about three months to complete. And Husky used the Henry Goodrich to drill its Glenwood H-69 well between January and March 2010. The well remains listed as suspended. “We safely executed the last Mizzen well and without issues all the way through the winter and we tested it,” Statoil’s drilling project manager Jim Beresford says. “We’re obviously committed to the offshore area here with the amount of work and activity we’ve got going on.” The Henry Goodrich has deepwater capabilities but normally works in ocean areas covering places such as the Jeanne d’Arc Basin, a relatively shallow but sprawling section of seabed lying within Newfoundland and Labrador’s Grand Banks that has proven highly productive for oil companies operating there.

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Now, Statoil is back in the Flemish Pass hoping that this next round of delineation drilling will prove the commercial potential of Mizzen. “We’re holding on to that vision of becoming a producing partner,” Statoil East Coast president Hege Rogno says. “To do so, we’re going through the steps of getting the acreage and then exploration drilling and, hopefully at some stage, a development project.” The Norwegian-based company will use the Henry Goodrich to bore a second well, called Fiddlehead, immediately after it finishes working on Mizzen. The Fiddlehead location is south of the Terra Nova oilfield in the Jeanne d’Arc Basin in water only 100 metres deep. Besides paying $10.4 million for the Fiddlehead permit, Statoil, in conjunction with Repsol E&P Canada Ltd., bought Exploration Licence 1123. Situated north of Mizzen, that licence is in water about 2,900 metres deep. Statoil completed a seismic survey of the parcel last September. “We just finished up a seismic campaign…in the northern Flemish Pass Basin that was 1,600 square kilometres of mostly 3-D but some 2-D seismic,” Beresford says. Elsewhere, Newfoundland and Labrador Crown corporation Nalcor Energy in September invested $6 million in a large-scale 2-D seismic survey of a parcel in Newfoundland and Labrador waters.

The two-year project is being conducted by TGS-NOPEC Geophysical Company, which provides geoscience data and services to oil and gas companies worldwide. “Partnering in the survey will put us in a tremendous position to understand and promote the province’s offshore prospectivity,” Nalcor vice-president Jim Keating says. “The pre-competitive release of this multi-client survey will certainly lead to a greater interest in our offshore from the world’s exploration companies.” Onshore, East Coast activities still pivot primarily on exploration, with the search for and potential extraction of shale gas in New Brunswick stirring, left and right, the pot of public perception there and across North America. The province’s population is torn over exploitation of the jurisdiction’s potentially huge quantities of shale gas resources as environmentalists, fearing that drilling for the relatively clean energy source could contaminate New Brunswick’s freshwater sources, take to the protest trails. They want a moratorium placed on the activity, something the provincial government opposes. Instead, the government would like to see New Brunswick’s conventional gas and shale gas exploration pursuits deliver development, production and desperately needed revenues that could be spent on reducing the province’s crushing debt, now approaching $10 billion. The climbing deficit could surpass $1 billion next year.

ADVERTISERS ’ INDE X

Baker Hughes Canada Company. . . . . . . . . . . . . inside front cover Canadian Society for Unconventional Resources (CSUR). . 18 Canadian Standards Association. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Crosbie Salamis Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Halliburton. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . outside back cover Kenwood Electronics Canada Inc. . . . . . . . . . . . inside back cover Kubota Canada Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

What makes a resource unconventional? The oil or gas produced from an unconventional well is no different than that which is produced from a conventional well. The methods by which these resources are extracted use progressive, or unconventional, technologies which is why industry refers to these resources as “unconventional”. CSUR is active across Canada with efforts to facilitate communication between the unconventional oil and gas industry, provincial, federal and municipal governments, the public, First Nations and the media.

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