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8 J A N U A R Y / F E B R U A R Y 2 0 1 2 • O I L & G A S I N Q U I R E R

F E A T U R E S

The long runBy Darrell Stonehouse

Enhanced recovery key to unlocking full value from resource plays

New life for old reservoirsBy Darrell Stonehouse

Radcan’s horizontal radial jetting technology opens up more of the formation to production

Changing directionBy Darrell Stonehouse

With natural gas prices collapsed, the hunt is on for oil and liquids in northwestern Alberta

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G E N E R A l N E w S

T E c h N o l o G Y N E w S

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I N E V E R Y I S S U E

51 Southern Alberta• Alberta enjoys record land sale year

By Richard Macedo

55 Saskatchewan• Bakken, Shaunavon land sale

hot spots in 2011

By Richard Macedo

57 Northern Frontier• Red tape may have strangled

Mackenzie gas prospects, says

ex-CEO

By Pat Roche

31 Gas demand rising fastBy Lynda Harrison

59 Insulation on demand

35 British Columbia• B.C. land sale revenue down sharply

in 2011

By Richard Macedo

39 Northwestern Alberta• Bellamont to target Montney oil in 2012

43 Northeastern Alberta• Oilsands needs to continue

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says outgoing Suncor boss

By Richard Macedo

47 Central Alberta• Producers to focus on drilling Duvernay

By Richard Macedo

62 Political Cartoon12 Stats at a Glance

61 Business Intelligence• Tax implications of expanding your

business into the United States

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Editor’s Note


Natural gas prices reached a 10-year low in December, averaging $2.65 per gigajoule on Alberta markets.

And there’s very little optimism it will recover much this year. Analysts at AJM Deloitte are forecasting AECO prices of around $3.5 per thousand cubic feet in 2012.

Yet some are saying 2012 could be the bottom, with prices gradually rising going forward. AJM Deloitte is forecasting $4 per thousand cubic feet in 2013, steadily climbing to $6.5 per million cubic feet by 2021. This is a far cry from the over $10 per thousand cubic feet enjoyed just five years ago, but it takes into account the new supply and demand realities facing gas producers.

ARC Financial Corp. managing director Peter Tertzakian says despite current low prices, “gas is the fuel of the future.”

Speaking at the Calgary Petroleum Club, Tertzakian said global consumption recently sur-passed 300 billion cubic feet per day and is growing at approximately three or four per cent per year, which is about two times the rate of oil production growth.

In 2010, demand growth in the Asia Pacific market was 13 per cent, and with Japan’s current nuclear outages and its replacement with natural gas, Tertzakian expects even stronger demand to be reported for this year.

The price spread between North American gas and the Asia Pacific region is huge, with prices across the ocean averaging around $16 per thousand cubic feet, more than four times local prices.

Tertzakian said North American gas is currently “orphaned,” with no access to premium mar-kets. But that could change as liquefied natural gas export facilities are built.

“We are a free market and a free market has ways of working these things out, and we will be the beneficiaries, so I’m not really clear why people are so bearish on price,” he said, adding the current price spread will eventually be reduced.

The challenge facing many producers, however, is surviving until prices start their upswing.In this month’s issue, we look at how natural gas–weighted companies in northwestern

Alberta are weathering the storm. The answer is by drilling formations with liquids-rich content or switching to oil exploration while building plans to export growing gas resources.

Looking at the massive amount of gas resource in play in the Doig/Montney formations and the huge volume of potential resource to be explored in northwestern Alberta in the Duvernay and Nordegg, future supply coming out of the region will likely be huge.

In this month’s issue, we also look at enhanced recovery schemes in western Canadian tight oil plays. It seems odd to be talking about enhanced recovery in plays that are mostly in early development, but operators are already advancing schemes to capture billions of barrels of resource not recoverable through extended-reach horizontal drilling and multistage fracturing. Gas-flood and waterflood pilots are underway in Saskatchewan and Alberta, and so far they look very promising.

Is this the bottom for natural gas?

N E X T I S S U E

Want to sound off on any content in Oil & Gas Inquirer?

Send your emails to [email protected]. Please mark them as "Letter to the Editor" if you want them published.

March 2012In our March issue, Oil & Gas Inquirer looks at emerging tight oil plays in southern Alberta and reviews technologies for increasing production from heavy oil resources.

Vol. 24 No. 1eDitorialEDITOR Darrell Stonehouse | [email protected] WRITERS Lynda Harrison, Richard Macedo, James Meadow, Pat RocheEDITORIAL ASSISTANCE MANAGER Samantha Kapler | [email protected] ASSISTANCE Kate Austin, Laura Blackwood, Marisa Kurlovich

CreativePRINT, PREPRESS & PRODUCTION MANAGER Michael Gaffney | [email protected] SERVICES MANAGER Tamara Polloway-Webb | [email protected] LEAD Cathlene OzubkoGRAPhIC DESIGNER Peter MarkiwCREATIVE SERVICESChristina Borowiecki, Janelle Johnson, Jeremy [email protected]

SaleSSALES MANAGER—ADVERTISING Maurya Sokolon | [email protected] ACCOUNT EXECUTIVE Diana SignorileSALES Ellen Fraser, Rhonda Helmeczi, Nicole Kiefuik, Jeff LeHoux, David Ng, Sheri StarkoFor advertising inquiries please contact [email protected] TRAFFIC COORDINATOR—MAGAzINESDenise MacKay | [email protected]

DireCtorSPRESIDENT & CEO Bill Whitelaw | [email protected] & DIRECTOR OF SALES Rob Pentney | [email protected] OF EVENTS & CONFERENCES Ian MacGillivray | [email protected] OF the daIly OIl bulletInStephen Marsters | [email protected] OF DIGITAL STRATEGIES Gord Lindenberg | [email protected] OF CONTENT Chaz Osburn | [email protected] OF PRODUCTION Audrey Sprinkle | [email protected] OF MARkETING Kim Walker | [email protected] OF FINANCE Ken Zacharias, CMA | [email protected]

oFFiCeSCalgary 2nd Floor, 816 – 55 Avenue N.E. | Calgary, Alberta T2E 6Y4Tel: 403.209.3500 | Fax: 403.245.8666 Toll-Free: 1.800.387.2446Edmonton 6111 – 91 Street N.W. | Edmonton, Alberta T6E 6V6Tel: 780.944.9333 | Fax: 780.944.9500Toll-Free: 1.800.563.2946

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Made in Canadathe opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

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StatsAT A GLANCE

WCSB Oil & Gas CompletionsSource: daily Oil bulletin

M O N T H O I L G A S D R Y S E R V I C E T O TA L

Dec 2010 1,061 559 78 238 1,936Jan 2011 409 201 33 17 660Feb 2011 723 378 38 99 1,238

Mar 2011 1,069 1,081 64 164 2,378Apr 2011 618 509 46 81 1,254Jun 2011 428 197 12 183 820

Jul 2011 298 97 15 88 498Aug 2011 922 262 28 80 1,292Sept 2011 1,448 445 24 155 2,072

Oct 2011 1,153 321 20 49 1,543Nov 2011 1,170 331 27 42 1,570Dec 2011 988 359 27 115 1,489

Wells Drilled In British ColumbiaSource: B.C. Oil and Gas Commission

* from year to date

M O N T H W E L L S D R I L L E D C U M U L AT I V E *

Dec 2010 49 700Jan 2011 62 62Feb 2011 69 131

Mar 2011 55 186Apr 2011 41 172Jun 2011 54 419

Jul 2011 56 479Aug 2011 40 519Sept 2011 92 611

Oct 2011 35 646Nov 2011 92 738Dec 2011 58 796

*From year to date

Saskatchewan CompletionsSource: daily Oil bulletin

M O N T H OIL GA S OTHER TOTA L

Dec 2010 340 2 11 353Jan 2011 136 4 3 143Feb 2011 321 6 7 334

Mar 2011 316 8 4 328Apr 2011 183 11 11 205Jun 2011 217 25 89 331

Jul 2011 185 5 3 193Aug 2011 413 2 13 428Sept 2011 352 4 29 385

Oct 2011 457 29 46 532Nov 2011 524 4 32 560Dec 2011 332 4 61 397

Alberta CompletionsSource: daily Oil bulletin

M O N T H O I L G A S O T H E R T O TA L

Dec 2010 676 403 294 1,373Jan 2011 226 145 82 453Feb 2011 353 294 127 774

Mar 2011 650 974 222 1,846Apr 2011 419 472 112 1,003Jun 2011 209 124 100 433

Jul 2011 105 43 97 245Aug 2011 452 183 93 728Sept 2011 1,028 357 146 1,531

Oct 2011 626 259 19 904Nov 2011 557 241 36 834Dec 2011 568 300 72 940


Number of rigs at work as of Jan. 13, 2012.

65083%Percentage of drilling fleet working in the

first week of January.

F A S T N U M B E R S

Drilling Activity: CBM & BitumenAlberta, December 2011 Source: daily Oil bulletin

C O A L B E D M E T H A N E B I T U M E N W E L L S

Alberta Dec 11 Dec 10 Dec 11 Dec 10

Northwestern Alberta 7 1 14 12

Northeastern Alberta 0 0 71 175

Central Alberta 24 32 54 165

Southern Alberta 56 51 0 0

TOTAL 87 84 139 352

Service Rig Count by Province/TerritoryWestern Canada, January 13, 2012 Source: Rig locator

A C T I V E D O W N T O TA L A C T I V E

Western Canada (Per cent of total)

Alberta 440 199 639 69%

British Columbia 34 7 41 83%

Manitoba 19 2 21 90%

Saskatchewan 161 32 193 83%

WC Totals 654 240 894 73%

QC - 1 1 0%

Drilling Activity: Oil & GasAlberta, December 2011 Source: daily Oil bulletin

O I L W E L L S G A S W E L L S

Alberta Dec 11 Dec 10 Dec 11 Dec 10

Northwestern Alberta 182 78 160 120

Northeastern Alberta 73 176 1 4

Central Alberta 217 369 40 67

Southern Alberta 96 71 98 217

TOTAL 568 694 299 408

Drilling Rig Count by Province/TerritoryWestern Canada, January 13, 2012 Source: Rig locator

A C T I V E D O W N T O TA L A C T I V E

Western Canada (Per cent of total)

Alberta 479 91 570 84%

British Columbia 64 12 76 84%

Manitoba 22 2 24 92%

Saskatchewan 100 14 114 88%

WC Totals 665 119 784 85%

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FEAturE

The advent of extended-reach horizontal wells, multistage fracturing and pad drilling methods has opened up a whole new world for North American oil producers.

Billions of barrels of oil resources formally trapped in tight rock are now within reach.

While the tight oil drilling and completion revolution is still in its early stages, producers are already looking to enhanced recovery technologies to capture more resource and better manage decline rates in tight oil plays.

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FEAturE

John Wright, president and chief executive officer of tight oil pioneer PetroBakken Energy Ltd., says while new drilling and completion technologies pro-vide high initial production, they come at a high cost and that production quickly declines. Enhanced recovery extends the production life of the well and increases ultimate recovery, adding significant value to the well.

“These wells are capital-intensive, require a lot of innovation, practice and execution,” he explains. “Still, at the end of the day, what they give you is a very high rate of initial production that declines exceptionally rapidly. But they provide a very long 20–30-year tail of production. After the first two years, you basically have an annuity on your hands.”

Wright says the goal of enhanced recovery schemes in oil resource plays

is to maintain field pressure to get max-imum returns on that annuity.

“There’s nothing magic about this. This is lousy, crappy rock saturated with oil. It’s very, very low permeability and it’s very, very difficult to tease the oil out. Without these horizontal wells, there would be no production at all,” he explains. “The idea with any pressure maintenance scheme is to push oil out of the rock and leave the injector f luid behind. If you think of the field as a long-life annuity, what we’re trying to do is attenuate the decline and extend its economic l i fe by increasing the recovery factor and the ultimate recov-ery of each well.”

PetroBakkeN teStiNg NatUral gaS FlooDST he Ba k ken play i n sout hea ster n Saskatchewan was the first tight oil play

to be exploited in western Canada and is also the earliest to test enhanced oil recovery (EOR) technologies.

PetroBakken looked at a number of different methods, including waterfloods and CO2 floods, but has opted for natural gas injection on its Bakken land base.

In the third quarter of 2011, the com-pany reported it had its first gas injec-tion well on injection with a total of five planned by year-end. If gas f looding works, PetroBakken has identified about 100 locations, probably about 20 a year over the next five years, which will result in about half of its Bakken production on EOR in that period.

“The beauty of this is that we are actually going to start injecting our own solution gas,” says Wright.

At today ’s prices, natural gas is almost a waste product, so in putting “it

“the beauty of this is that we are actually going to start injecting our own solution gas.”

— John Wright,president and chief executive officer,

PetroBakken Energy Ltd.

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FEAturE

in the ground, it becomes a storage project,” he says.

“Displacing oil out of the ground and ultimately producing that natural gas back on final depletion could be an optimal way to get the most value out of the Bakken, and we are pretty excited about the potential that this offers for us,” he says.

The company has 1.8 billion barrels of light oil in place in the tight Bakken formation. Only five per cent has been booked as proved-plus-probable reserves.

“We actually think there’s a poten-tial for reserve booking of more than 25 per cent once you include the effect of our enhanced oil recovery programs,” Wright told the company’s 2011 annual meeting.

PetroBakken chose the natural gas flood because the rock isn’t homogenous and traditional waterflooding wouldn’t work on significant portions of its Bakken lands, the company’s modelling showed.

The goal is to increase reservoir pressure, which falls as oil is extracted. In the areas targeted for natural gas enhanced recovery, the permeability is so low that it isn’t possible to inject water fast enough to offset production from Low gas prices make injecting natural gas cheaper than using CO2.

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FEAturE

nearby oil wells, says Rene LaPrade, PetroBakken’s senior vice-president of operations. Hence, there wouldn’t be suf-ficient re-pressuring of the reservoir to enhance oil recovery.

CO2 would work, a brief test indi-cated. In February 2010, PetroBakken shut in one of its Bakken wells for a very short CO2 injection and soak period. In the ensuing 14 months, two offsetting wells each recovered more than 6,000 barrels of additional oil, Wright said.

This test and reservoir modelling convinced PetroBakken that gas injec-tion would enhance oil recovery. There are two reasons why the company is piloting dry natural gas injection rather than CO2.

The first is an abundant supply of cheap solution gas from the company’s own nearby gas plant. The second is existing facilities that can be used with-out worrying about corrosion. CO2 would change how the company could use its facilities, which in most cases are bare steel that would be highly susceptible to corrosion.

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FEAturE

isn’t ruling out the possibility of injecting water—or other fluids—for future projects in other areas of the Bakken.

PetroBakken is using the pilots to test different concepts or well config-urations. For example, in the second pilot—which will inject natural gas at a rate of about two million cubic feet per day—gas will be injected along the entire horizontal section of the injec-tion well, so the f lood front will hit the toe of each of four perpendicular pro-ducing wells.

“As gas breaks through at the toe of each well, we have the ability to simply plug off the toe area of the producing horizontal well and mitigate the cycling of the gas at that port,” LaPrade explains. “The front would continue to move along the horizontal producing leg to the next port, where we would again plug that port off as the gas breaks through.”

The company hopes to make public some preliminary data from the first pilot by year’s end, and to release fur-ther results by mid-2012. If the results are favourable, “I would expect there’d be a significant acceleration in pilots,” says LaPrade.

CreSCeNt PoiNt eNergy goeS the traDitioNal waterFlooD roUteBakken competitor Crescent Point Energy Corp. is testing more traditional water-f lood techniques to enhance recovery both in the Bakken and at its Shaunavon play in the southwest.

“To us, it is the next leap in tech-nology and it moves us back into more conventional technologies,” Crescent Point president and chief executive officer Scott Saxberg says. “It’s a game-changer for how the Bakken will be developed and it will bring long-term value growth. It will basically, over time, lower decline rates in the field to the point we will be spending lower amounts of capital to maintain produc-tion levels and it will free up cash f low for other areas.”

Crescent Point began its Bakken waterflood pilot in 2008 and now has 17 injector wells up and running.

“We’ve seen a positive response from all injectors,” says Saxberg.

The economic impact of the water-f lood on cash f low is huge, he adds. High decline rates on newly drilled wells means that to maintain production rates,

Crescent Point would have to drill five wells for every injector, Saxberg says.

Typical wells in the Bakken come in at an average 200 barrels of oil per day and decline about 70–75 per cent in the first year before f lattening out at 30–40 barrels per day. The two pro-ducers in Crescent Point ’s f irst pilot were producing at 100–150 barrels per day this winter.

Greg Tisdale, chief financial officer of Crescent Point Energy, told a recent BMO Capital Markets Corp. conference that the company expects waterf loods will increase the recovery factor from 19 per cent to 30 per cent. Tisdale said Crescent Point expects the waterf lood scheme w il l a l low the company to increase recovery by around 307,000 barrels per well, and that this wil l transfer into increased economic value for the company.

“Three wells under primary pro-duc t ion wou ld b e wor t h a r ou nd $18 million,” he explained. “Under water-flood, the value of those wells would be $24.6 million.”

With the huge amounts of oi l in place in the Bakken, the waterf lood

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FEAturE

scheme could mean a massive increase in ultimate recovery as well.

Bakken producers expect between 17 per cent and 19 per cent recovery is achievable from primary technologies based on eight wells per section. Preliminary data from the waterf lood suggests at least a 30 per cent recov-ery factor. The area that Crescent Point has initially targeted for waterflood has around 1.5 billion to two billion barrels in place. A 10 per cent increase in recovery factor means 150 million to 200 million barrels of potential incremental reserves, if Pilot 1 is right.

A key to the success so far of the Bak ken waterf lood has been f rack-ing the injector and producer wells to ensure water sweeps the oil from the rock.

Crescent Point also has three water-f lood pilots underway in the Lower Shaunavon resource in southwestern Saskatchewan. Wave Energy Ltd. began the first in 2008 before being bought by Crescent Point.

CraCkiNg the alBerta CarBoNateSThe Beaverhill Lake carbonate resource play at Swan Hills came into its own in 2011 as companies began reporting results from horizontal wells completed with multistage acid fracs. While the play is in its early stages, waterf lood tests are already underway.

Arcan Resources Ltd. has over 170 net sections of land in the play at Swan Hills with an estimated 700 million barrels of oil equivalent in place. The company says it has over 400 potential horizontal drilling locations in play. Yet, despite that inventory, it is already work-ing on waterflood schemes to drive long-term production.

At its Deer Mountain Unit 2, Arcan has drilled 17 horizontal wells. It has nine active injector wells operating and will add an additional seven injec-tors in 2012.

At its Ethel property, it is beginning a waterflood test as well, with plans to convert three wells into injectors and drill six new injector wells in 2012.

If successful, the size of the prize for Arcan will be huge. The company says that with waterf loods, it could recover up to 40 per cent of the 700 million bar-rels of oil equivalent on its lands. It adds that CO2 f loods could add an additional 20 per cent of oil from the play.

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Extended-reach horizontal drilling and multistage fractur-ing have created a f lurry of activity in mature oilfields across western Canada, adding billions of barrels of potential stores of oil and gas.

But it isn’t the only way operators can turn more of known resources into reserves.

Radcan Energy Services, Inc.’s horizontal radial jetting technology also shows promise in adding reserves through enhancing production from existing vertical wells—at a frac-tion of the cost of a multistage fracturing program.

“We bring new life to old reservoirs,” says Radcan presi-dent Dennis Page.

Horizontal radial jetting creates a borehole out from a verti-cal wellbore by blasting the formation with high-pressure fluid. The borehole can extend as far as 100 metres into the formation, with an average diameter of about four or five centimetres.

“You can think of it as either an extremely good perfora-tion gun because it can go out 100 metres, or you can think of it as an isolated or controlled frac,” says Radcan technical sales representative Greg Tucker. He adds that radial jetting technology can also be used to create frac pilot holes that direct fractures on a preferred path, and to create chan-nels for pressure maintenance programs like waterf loods or CO2 f loods.

Tucker says using the company’s radial drilling technol-ogy is dead simple. All the equipment comes on a single body-mounted truck unit. The operator provides a coiled tubing rig and a water supply. After placing an orientation shoe, a mud motor is used to drill out the casing. From there, a high-pressure nozzle connected to the f luid supply hose drills out into the reservoir. The nozzle continues to jet when it is pulled out, removing fines and cleaning the hole. Three jets drill

Radcan’s horizontal radial jetting technology opens up more of the formation to production

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the small hole going in and two large jets enlarge and clean the hole coming out.

“Only the hose goes into the formation, no coiled tubing,” says Page. “There is no formation damage—100 per cent powder comes out of the hole.”

Usually, holes are drilled out from the vertical wellbore in four different directions, often at the top and bottom of the target reservoir, to maximize contact with the formation.

All-in costs are around $60,000 to drill four laterals, and it takes about two days from start to finish.

Globally, Radcan’s horizontal drilling technology has been used on over 2,000 wells. Around 120 wells have been treated in Canada with strong results so far.

In the Cardium sandstone, wells drilled with the radial drilling technology have reported production increases rang-ing from 30 to 300 per cent. In the Midale carbonates at Weyburn, Sask., production increases of 100–150 per cent have been reported.

“The oldest well to date has been a wel l dr i l led in 1957 in the Midale field,” says Page. “There has been a 10 0 per cent susta i nable increase in production.”

Tucker says while radial jet t ing tec hnolog y work s on both new and old wells, R adc a n i s t a r get i ng old fields with the technology. Many old f ields have only four vertical wells per sec-tion drilled, with a limited drainage radius of around 30 metres around the well-bore. The radial jetting tech-nology extends that radius out to 100 metres, accessing more of the resource without the high price of re-entering wells to drill long horizontal legs and fracking them.

“It ’s a c heaper mea n s to get outside the [nearby]

wellbore. We are getting out double that far,” he explains. “It will also cut down on suspended or abandoned wells because it makes it more economic to keep producing these wells and recovers more oil.”

Page says the horizontal radial jetting technology provides a cheaper, better answer for junior companies looking to opti-mize production and recovery while managing costs.

“They can take a lateral well and turn it into a horizontal with our technology,” he explains. Major oil companies can quickly increase production from old fields while accessing more reserves.

“The biggest challenge we have is getting people to try it,” says Page. “People are resistant to change. We had one con-sultant with 30-plus years’ experience say it was hocus pocus. After seeing it work he said, ‘I was your worst enemy three days ago. Now I am your best friend.’ If we can find these guys and turn them around, we’ll be on our way.”

“ the oldest well to date has been a well drilled in 1957 in the Midale field. there has been a 100 per cent sustainable increase in production.”

— Dennis Page,president,

Radcan Energy Services Inc.

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Over the Christmas break, AECO whole-sale natural gas prices reached a low of $2.65 per gigajoule, marking a 30 per cent price decline in 2011 compared with 2010.

The natural gas price collapse is result-ing in producers changing direction across western Canada, with oil and natural gas liquids becoming the preferred drilling target, according to Petroleum Services Association of Canada president and chief executive officer Mark Salkeld.

“We all know that oil and gas activity is predicated on price,” said Salkeld in releas-ing its annual forecast late in 2011. “In 2012, oil prices will be adequate to sustain oil drilling-related activity. Gas pricing, on the other hand, remains relatively low and we are not expecting any significant price turnaround in 2012. Thus we are expect-ing to see 80 per cent of wells drilled in the basin be oil and liquids-rich gas wells. This compares to an expected 74 per cent of drilled wells being focused on oil in 2011.”

The Canadian Association of Petroleum Producers (CAPP) shares this view. In a year-end interview with the Daily Oil Bulletin, Dave Collyer, president of CAPP, said some gas plays will get attention, but overall he expects it to be a tough year on the natural gas side of the business.

“Tight/shale gas will continue to attract interest due to the resource potential and

With natural gas prices collapsed, the hunt is on for oil and liquids in northwestern AlbertaBY DARRELL STONEhOUSE

changingdirection


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the prospect of the development of LNG [liquefied natural gas] facilities on the west coast, but will continue to be challenged by the low price environment for natural gas,” he said. “In the conventional areas, drilling will focus largely on oil prospects. There’s no question companies are less inclined to focus on dry gas prospects because explora-tion and development remains severely chal-lenged by surplus supplies and low prices. Gas liquids remain a popular target.”

What is happening across the Western Canadian Sedimentary Basin will hold true for northwestern Alberta as well, with producers focused on liquids and on proving up shale gas supplies for potential overseas export. But while targets change, activity in the petroleum-rich region of the province is expected to continue growing as operators move into the develop-ment phase on existing plays and attempt to prove up massive new resources.

Guide Exploration Ltd. is a major land-holder in the northwest, with over 450,000 net acres in the Peace River arch. Formerly Galleon Energy Ltd., Guide is now being led by Bill Andrew, a founder and long-time chief executive officer of conventional oil giant Penn West Exploration Ltd. In releasing the company’s third-quarter results, Andrew told shareholders that in the near term the company plans on focusing on oil and wet gas plays on its land base.

“Our near-term goal is to ensure that, through focused development in oil-rich areas of our portfolio, we meet and hopefully exceed our production and funds flow targets

for 2012,” he says. “In addition, we will be implementing an active exploration program in 2012, keying on our large acreage resource plays in the Peace area.”

Andrew says Guide has set a capital budget of $125 million to $130 million for 2012, and plans to drill 40 wells. The com-pany’s focus will be on Montney oil in the Peace area, Doig oil around Worsley and wet Montney gas in the Smoky area.

On its Peace-area Montney oil play, Guide drilled 20 wells in 2012, and has 15 more sec-tions ready for development delineation. It has another potential 10 or 20 sections that may be developed. The company is moving towards pad drilling in the area and plans on down-spacing to four to eight wells per sec-tion. It is also working to optimize its horizon-tal completion design in the play. Andrew says in the past the company has taken a cookie-cutter approach to its horizontal/multistage fracturing efforts. It is now looking at refining these efforts for each of its plays. So far, Guide has increased its fracking density on its Upper Montney wells and increased the size of fracs from three to five tonnes per stage. It is con-tinuing to evaluate its drilling and frac tech-nology and exploring different fluids, and frac density and intensity options.

Further ahead, Guide also has large land positions in the emerging Duvernay and Nordegg plays. In the Nordegg, the company has 125,000 net acres and plans an initial horizontal test well this year. A Nordegg ver-tical well drilled in 2008 proved the play’s potential. The target is shallow oil. In the

Duvernay, Guide has 350,000 net acres and plans a wildcat well this year to test for oil as well.

Birchcliff Energy Ltd. is another major player in northwestern Alberta, with an undeveloped land base of 490,000 net acres. In 2011, Birchcliff focused on proving up its Montney/Doig natural gas play, with 66 wells drilled into the play to date. President and chief executive officer Jeff Tonken told shareholders in the company’s third-quarter report that the play has evolved into a full-cycle exploration, exploitation development and production program.

“We continue to aggressively add to our undeveloped land inventory, we continue to build out our infrastructure, we are now drilling infill wells on 300-metre inter-well spacing. Further evaluation is being con-ducted to support down-spacing to less than 300 metres, as has been done by other com-petitors on the play,” he said.

The company has around 1,900 drilling locations on its Montney/Doig play.

Like Guide Exploration, Birchcliff is also active in the Worsley light oil play, where it drilled 14 horizontal development wells in 2011. It has identified 112 drilling locations in the play and has begun a waterflood at Worsley to increase recovery.

Birchcliff also has huge land positions in emerging plays across the northwest. It has 616 net sections in the Nordegg play, 648 sections in the Banff/Exshaw play and 196 sections in the Duvernay.

“As is consistent with our corporate strategy, the majority of this land is in large contiguous blocks at 100 per cent working interest,” noted Tonken. “Some of these lands are also prospective for the Montney/Doig natural gas resource play or the Worsley light oil resource play. We are early in the development of these new resource plays, but based on the high level of industry activity and our internal tech-nical evaluation, we are optimistic about their potential ultimate value.”

Birchcliff is also active in finding new markets for the huge gas supply in north-western Alberta and northeastern British Columbia. It is one of the founding members in the BC LNG Export Co-operative LLC that is involved with Douglas Channel Energy Partnership in the development of a small-scale LNG project in Kitimat, B.C., with a planned start-up by early 2014.

With strong oil prices, the Peace River oilsands will also be a source of growth for the industry in 2012. Baytex Energy Corp.

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reported in November that production from its Seal properties averaged approximately 17,800 barrels per day in the third quarter, an increase of 24 per cent from the second quarter of 2011. In the third quarter of 2011, it drilled seven cold horizontal producers at Seal, including its first drilling on its Reno-area properties acquired earlier this year.

“Our most common multilateral well design includes eight approximately 1,400-metre-long laterals, which are often augmented with several shorter ‘stubby’ laterals to drain the region around the intermediate casing point to the starting point of the 1,400-metre-long laterals,” com-pany president and chief executive officer Anthony Marino reported to shareholders. “Three of the wells drilled in the third quar-ter and two of the wells drilled in the second quarter established average 30-day peak production rates of approximately 340 bar-rels per day per well. Although we have not yet recorded a 30-day peak production rate on any wells drilled on the lands acquired at Reno earlier this year, the first two wells drilled have initial production rates averag-ing approximately 375 barrels per day per well, based on the first two weeks of produc-tion. The two Reno wells had an average of six full-length horizontal laterals per well, plus an average of four ‘stubbies’ per well.”

At its Cliffdale cyclic steam stimulation (CSS) project at Seal, Baytex continued pro-duction operations during the pilot well’s third cycle. The company is projecting a steam to oil ratio of approximately 1.9 for this cycle, one of the best in the industry. Four additional CSS project wells drilled in the first quarter con-tinued pre-steam cold production in the third quarter at rates of approximately 20 barrels per day per well, while awaiting completion of steam-generation facilities. The company has received regulatory approvals to install oil- and water-handling facilities and steam distribution piping at Cliffdale. Construction has commenced and Baytex expected to begin steam injection late in the fourth quarter of 2011. To complete its first 10-well commer-cial CSS module, Baytex also planned to drill an additional five horizontal CSS wells in the fourth quarter of 2011.

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General News


Gas demand is beginning to catch up with supply driven by the shale gas revolution, says analyst Peter tertzakian.

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Its popularity surged again starting in the 1930s with the ability to weld high-pressure pipelines that could carry gas long distances, and the resulting construction took place to usher in the home-heating era.

Now, because multi-frac horizontal drilling technology has unlocked shale gas, taking production from one billion cubic feet per day in 2006 to the current 22 billion cubic feet per day, its value has dropped again. The price of gas is down to about $4 per thousand cubic feet, while on the other side of the world, in Asia, it’s now about $16 per thousand cubic feet, he said.

Gas has gone from darling to orphan continuously, but it continues to grow. “The precedence suggests you can go from orphan to darling very fast.”

This is a period of very extreme changes, whether it’s oil, gas or energy as a whole, he said. “Do not believe any number that you see out there without investigat-ing it in great detail. If you are doing your strategic planning, if you make dollar deci-sions, do not take verbatim what people and agencies and others are telling you. Do not follow the herd’s mentality. Do your homework. Do not believe what you see.”

Tertzakian said there are forces at work to close the Canada-Pacific arbi-trage. “That’s a big arb. The whole North America versus global gas price arb is just gigantic. We are a free market, and a free market has ways of working these things out and we will be the beneficiaries, so I’m not really clear why people are so bearish on price when it comes to recognizing that the arb will eventually be closed.”

According to his research, the top 10 publicly traded North American produc-ers’ gas production, representing a third of U.S. production, has levelled off after a growth period.

He believes there will be less gas deliverability going forward. From 2001 to about 2006, the industry had to replace 12 billion cubic feet of gas per day. The treadmill’s going faster and current replacement volumes of 22 billion cubic feet per day have to turn over, requiring $80 billion to $90 billion a year of capital just to offset declines, he said.

Meanwhile, there’s an under-reported phenomenon he called “adopting the orphan.” The demand side is now getting comfortable with the low price of gas, almost to the point of being considered again for industrial use, and is already replacing coal to a certain degree, said Tertzakian.

Natural gas is being ignored at producers’ peril because demand is growing faster than production, so eventually “something’s got to give,” says a leading energy economist.

“Gas is the fuel of the future,” said Peter Tertzakian, chief energy economist and managing director for ARC Financial Corp. “Do not forget that. It is grow-ing tremendously in other parts of the world, and so it should. It is a compelling fuel and a compelling substitute, and the rate of growth is comparable to when the Westminster Gas Light and Coke Company took root in the early 19th century.”

Gas has undergone surges and ebbs in popularity ever since, he told a capacity crowd at the Calgary Petroleum Club in a talk entitled Natural Gas: An Orphan’s Story.

While cutting back on gas production right now makes sense “from a profit-maximizing standpoint,” it just doesn’t seem right, he said. “People want the stuff and you’re orphaning it. That in itself is sort of a very qualitative argument that at some point something’s got to give,” he told an industry audience.

According to Tertzakian, global con-sumption recently surpassed 300 billion

cubic feet per day and is growing at approx-imately three or four per cent per year, which is about two times the rate of oil pro-duction growth.

In the Asia Pacific, gas output is increasing about seven or eight per cent per year, compounding on a very large volume of about 50 billion to 55 billion cubic feet per day. “That’s like four billion cubic feet per day per year. That’s like four Kitimat [B.C.] terminals every year.”

In 2010, growth was a “staggering” 13 per cent and with Japan’s current nuclear outages and its replacement with natural gas, Tertzakian expects even stronger demand to be reported for this year. “It is the darling as it was in the early-to-mid 19th century…. It is a dar-ling in another part of the world.”

Then, as now, oil was more highly valued and the gas that came up with it during pro-duction was so little valued it was simply vented. “Who needs this stuff? Natural gas is the least appreciated, consequently it’s the most abused of the mineral resources in popular use,” said Tertzakian, bestselling author of A Thousand Barrels a Second and The End of Energy Obesity.

Gas demand rising fastBy Lynda harrison

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General News

Western Canada has had a land sale spending splurge this year thanks to the multi-billions being spent in Alberta, and while producer wallets likely will not open like this for land in 2012, it could mean more capital will be put toward churning the drill bit.

In a presentation, Scott Treadwell, vice-president, equity research, oil and gas services, with TD Securities, noted that drilling “has some work to do to ad- equately explore land recently acquired.”

While the paradigm has shifted from that of pre-2008, “we would argue that over time, multi-well pads will deliver well densities approaching that of the down- spacing era and CBM [coalbed menthane] activity of 2000–06.”

After a talk at the Calgary CFA Society’s oil and gas services forecast, he said that unless land prices go way up or another land grab happens, which is unlikely, capital will be sent toward the drill bit.

“We’ll go away from land and onto the drill bit and there’s a meaningful capital shift associated with that,” he told the audience.

“Resource plays typically benefit pumpers in our view, but any service name with the scale to service these operations stands to benefit. Logistical efficiency and

scale are very important in those opera-tions,” Treadwell added.

He noted that over the last 12 months, over 20,000 sections of land have been leased to producers and brokers in the Western Canadian Sedimentary Basin, mostly in Alberta.

In terms of predicting drilling on the land, Treadwell laid out an equation, which included the assumption that 20 per cent of the land supports high-density wells (pads, multilaterals and down-spaced verticals), with “high density” meaning 15 wells per section (40-acre spacing or one pad per sec-tion) and a normal development life of five to seven years.

This led to an estimate of 8,500–12,000 wells per year on this land base alone.

“That’s on 20 per cent of the land that’s been leased in the last 12 months,” he said. “That’s not the other 80 per cent, that’s not existing plays, that’s not the next play that’s coming.

“The inventory is there, producers have already spent on land and that gives some visibility that we’re not running out of ideas.

“If you look at the top 10 parcels that have been sold in Alberta [in 2011], it’s $836 million or about $3 million per sec-tion,” Treadwell added. “Those sections, those big chunky bids, are not the way land sales were done five years ago.”

With resource plays, it’s less about the micro and more about the macro.

“So now, it’s all about having scale and so that means [being the] first in…. Get the land, delineate it, drill it and go from there,” he said.

Lara King, oilfield service analyst with Stifel, Nicolaus & Company, Incorporated, added one of the key impacts of the lengthy disconnect between oil and natural gas prices is a meaningful switch in what is being built today.

The change in focus on what producers are chasing has had an effect on, among other things, the type of drilling rigs that are needed and conversely the decimation of demand for rigs that efficiently drill shallow natural gas wells.

“In the U.S., back in 2008, 70 per cent of completions were targeting natural gas; that has dropped to 45 per cent in 2011 to date,” she said. “The story is even more extreme in Canada where the ratio has reversed. Completions have gone from 67 per cent gas in 2008 to 67 per cent oil in 2011.”

She added that Canada could have two million horsepower in various frac spread configurations by the end of 2012.

“This would be a 140 per cent increase over 2009 levels,” King said.

— DAILY OIL BULLETIN

Land rush signals coming drilling boom

“ We’ll go away from land and onto the drill bit and there’s a meaningful capital shift associated with that.”

— Scott Treadwell, vice-president, equity research, oil and gas services, TD Securities

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General News


Scotiabank expects geopolitical events will keep oil prices strong next year despite slow global economic growth.

T he ba n k e x pec t s West Te x a s Intermediate (WTI) crude will average US$95 a barrel in 2012, on par with its forecast of US$95 a barrel for this year. Brent crude is expected to average US$108 a barrel next year, down from an expected average 2011 price of US$111.

“You may ask: Why are oil prices hold-ing up over $100 when we have all these difficulties around the world in terms of slower global growth?” said Patricia Mohr, Scotiabank’s vice-president of eco-nomics and a commodity market special-ist. (Mohr regards Brent, not WTI, as the key benchmark.)

The commodity specialist cited three reasons why she expects oil prices to remain relatively high in 2012. The first is Saudi Arabia has been reducing its production to offset the increased output from Libya, which is now coming back on stream after being offline for a revolution.

The second reason is Iranian supply could be cut as sanctions tighten around the world.

Mohr said “a very significant geopolitical supply risk premium” has resurfaced with the International Atomic Energy Agency’s November 8 report to the United Nations. The agency’s weapons inspectors said they found evidence Iran has been trying to build an atomic bomb.

Mohr said it’s been known for at least 15 years that Iran has been trying to make nuclear weapons. “So I don’t think there’s anything to argue about…even though they say they’re not,” she said.

“W hat has happened since that November 8 report…came out [is] there has been a great deal of worry in world oil markets about a potential loss of Iranian supply—either through some kind of direct intervention—direct action—or because of the tightening of sanctions by other countries on Iran.

“And what is becoming difficult for the Iranians is the fact that many countries around the world now control the banking

transactions between their country and Iran, particularly Iran’s central bank,” Mohr said. “So it’s becoming more and more difficult to pay for Iranian crude. This is quite an important factor.”

However, a lot of Iranian crude is sold to China and India, Mohr said, adding that those countries won’t stop importing it.

She said the third reason Scotiabank expects oil prices to stay high next year is demand growth in China could rise because electricity constraints on the state grid could trigger stepped-up backup diesel generation.

Also, she said, there could be a lot of strategic buying for China’s second stor-age reserve, which is now ready. “If the prices eased just a little bit, they might take the opportunity to try and fill their strategic reserves.”

Mohr said the strength of oil prices this year has been linked to ongoing growth in world oil demand of about 900,000 barrels a day—all of it in emerging markets.

A t t he s a me t i me, non- OPEC (Organization of the Petroleum Exporting Countries) output increased by a mere 100,000 barrels of oil a day. In other words, there was almost no increase in non-OPEC supply this year. North Sea pro-duction plunged and there were technical

problems in Angola, maintenance outages on BP p.l.c.’s oil platforms in Azerbaijan and strikes in Kazakhstan.

As a result, 2012 could see “quite a rebound in non-OPEC oil supplies after only a 100,000 gain this year—with further growth in tight oil in Canada and the U.S., less maintenance in the Alberta oilsands upgraders, Canadian Natural Resources Limited’s Horizon project will be fully back on stream, less maintenance in the North Sea and more success in ramping up Brazilian offshore projects,” Mohr said.

On the downside for Canadian produc-ers (who get paid in U.S. dollars), Mohr expects a strong Canadian dollar this year. She said Canada’s currency is now a petro-currency, so when oil prices are high, the Canadian dollar will be strong.


Scotiabank predicts strong oil prices ahead

“ So it’s becoming more and more difficult to pay for Iranian crude. this is quite an important factor.”

— Patricia Mohr, vice-president of economics, Scotiabank, and commodity market specialist

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BRITISH COLUMBIA WELL ACTIVITY

British columbia

DEC/10 DEC/11

WELL LICENCES 74 66 ▼

DEC/10 DEC/11

WELLS SPuDDED 46 60 ▲

DEC/10 DEC/11

WELLS DrILLED 50 57 ▲

Source: Daily Oil Bulletin

the shale gas land boom cooled off in northeastern British Columbia in 2011. Analysts expect 2012 to be another quiet year.

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B.C. land sale revenue down sharply in 2011By Richard Macedo

For British Columbia, the weaker num-bers this year reflect the impact of low gas prices and the recognition that large tracts have been acquired by large operators in the most economically prospective areas of the Montney and Horn River, noted Gary Leach, executive director of the Small Explorers & Producers Association of Canada.

“Given these dominant factors are not changing in 2012, it is difficult to see a catalyst that will move the needle in B.C.,” he said. “We think there is potential for better investment levels if the government would consider some changes to their deep gas credit and even to their oil roy-alty framework that could encourage more investment, particularly from junior and intermediate producers.

“We hope to engage the B.C. government on discussions on these topics in 2012.”

Brad Hayes, president of Petrel Robertson Consulting Ltd., said for B.C. sales in 2012 to even match 2011, there will need to be some success in early wells in prospec-tive, but currently risky, areas like the Liard Basin, Cordova Embayment and northerly reaches of the current Montney fairway.

“Otherwise, the decline may well con-tinue,” he said. “I doubt there will be long-term weakness. I’m not sure what the next big thing will be, but with the advances we have been making in thinking and tech-nology, there’s sure to be something.

“If gas prices were sufficient to sup-port CBM [coalbed methane] spending, I think that economics and therefore com-pany interests would still tend to be more focused on lands marginal to the existing successful shale and tight gas plays.”

The Klappen and southeastern B.C. coal plays have a lot of issues with First Nations and environmental concerns, he pointed out.

“If something is to go in CBM, I would bet on the northeast-B.C. Peace River coal fields,” Hayes said.

British Columbia ended a weaker land sale year on a positive note, taking in $60.17 million in its final auction of 2011, the highest at a single sale in 2011.

A total of 42,347 hectares were sold at the December 14 sale at an average price of $1,420.82. For the year, the prov-ince collected $222.68 million in bonus bids on 191,529 hectares at an average of $1,162.66. This was the lowest bonus total since 1999, when $176.17 million rolled into provincial coffers.

In 2010, the natural gas–prone prov-ince collected $844.41 million in bonus bids on 381,132 hectares at an average price of $2,215.54.

Key parcels in the December sale included a group of four drilling licences covering 21,884 hectares located in the Red Creek North–Inga area, about 32 kilometres northwest of Fort St. John, B.C. Collectively, these licences earned

$44.4 million in bids at an average of $2,029.

The bonus high was produced by Plunkett Resources Ltd., which paid $13.93 million for a 5,797-hectare licence parcel. The broker picked up three tracts and several sections at 85-22W6, 85-23W6, 86 -22W6 a nd 86 -23W6. Windfall Resources Ltd. acquired an adjacent 5,804 -hectare l icence for $12.86 million at an average of $2,216. Also in the area, Scott Land & Lease Ltd. picked up a 4,481-hectare parcel for $10.31 million at an average price of $2,301. Stomp Energy Ltd. scooped up a 5,802-hectare licence for $7.29 million at an average of $1,257.

A 3,380-hectare drilling licence in the Aitken Creek North area, about 110 kilometres northwest of Fort St. John, attracted a bonus of $6.3 million at an average price of $1,862 per hectare.


British columbia

Advantage continues Glacier development

Meanwhile, the province is hoping that exporting liquefied natural gas (LNG) off coastal waters to the lucrative Asian market will help to boost upstream activity. But that likely won’t start hap-pening until around 2015. Hayes said that companies with a stake in the LNG facilities will probably do whatever they can to slow short-term investment com-mitments until more of the uncertainties around pipelines and permits have been addressed.

As of December 2010, there were a total of 98 producing shale gas wells in

the Horn River Basin, many still held confidential under terms of experimen-tal scheme approvals, the Oil and Gas Commission reported. Production from the Horn River group of formations accounted for 10 per cent of total produc-tion in the province.

The Montney tight gas trend continued to be the most active natural gas play in the province. A total of 383 wells targeted the Montney formation, accounting for 57 per cent of all wells drilled in 2010 and extending the play to the northwest into the fields of Altares and Town. Montney

production accounted for 26 per cent of the total production within the province.

One of the f irst unconventional resource plays in British Columbia was the Jean Marie formation. This formation has been on continuous production since the early 1980s, and output peaked from 2004–06. With a 30-year history, this play is now at a mature development stage, but a large expanse of undrilled acreage remains to be explored. The Jean Marie formation had 95 new wells drilled in 2010 and accounted for just over 10 per cent of annual production.

Capital expenditures for Advantage Oil & Gas Ltd. are anticipated to be at the low end of guidance for the second half of 2011 at approximately $120 million, due to delays resulting from the wet weather conditions at Glacier in the early part of the third quarter of 2011.

The company does not anticipate any concerns with completing its Phase IV development program by the end of the second quarter of 2012 as originally tar-geted. The company reported a net loss of just under $3 million in the third quar-ter of 2011 compared to a loss of roughly $660,000 over the same period of 2010.

Production in the quarter was on track and averaged 22,568 barrels of oil equiv-alent per day (92 per cent natural gas). Production during the second quarter was 23,719 barrels per day and included 845 barrels a day from assets sold to Longview Oil Corp. that closed on April 14. During the third quarter, production from Glacier was impacted due to planned facility downtime at its gas plant to complete the acid gas injection system and maintenance work conducted by TransCanada Corporation.

The company’s Phase IV development program at Glacier includes a 12-month capital estimate of $200 million with two key objectives: increase throughput capacity at the Glacier gas plant (100 per cent working interest) from 100 million cubic feet per day to 140 million cubic feet by the second quarter of 2012 and drill a sufficient number of wells to fill the company’s plant, and further evaluate the Middle and Lower Montney formations.

Wet weather conditions at Glacier resulted in a staggered start to Advantage’s capital program and while this has ini-tially delayed drilling and well completion

progress by approximately 1.5 months, the company does not anticipate any impact on completion of the Phase IV expansion targeted for the latter part of the second quarter of 2012. Only one drilling rig was able to start operations in late July with the remaining two drilling rigs delayed until mid-August.

Capital expenditures at Glacier during the third quarter of 2011 were $37.1 mil-lion and included the drilling of seven horizontal Montney wells (five Upper Montney and two Middle Montney)

and completion of the acid gas injec-tion system. As of the release of its third-quarter report, the company had drilled a total of 12 wells and its three contracted drilling rigs were drilling wells 13–15 of Advantage’s 30-well program. Completion operations had begun and the company anticipates providing initial well results this winter.

In October, Advantage success-fully commissioned the acid gas injec-tion system, which is part of the facility changes required to increase its Glacier gas plant throughput capacity. Additional plant modifications will be completed

during the first half of 2012 to complete the gas plant expansion.

In conjunction with the anticipated production increase at Glacier, Advantage production is forecast to grow 24 per cent to a June 30, 2012, exit rate of approxi-mately 29,000 barrels equivalent per day, at which time Glacier will represent 80 per cent of total production. This target would result in production growth of 138 per cent since the company began development at Glacier in 2008.


In conjunction with the anticipated production increase at Glacier, advantage production is forecast to grow 24 per cent to a June 30, 2012, exit rate of approximately 29,000 barrels equivalent per day, at which time Glacier will represent 80 per cent of total production. this target would result in production growth of 138 per cent since the company began development at Glacier in 2008.

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Nexen Inc. has reached an agreement with a consortium led by Japanese oil and natural gas producer INPEX Corporation to develop shale gas in the Horn River, Cordova and Liard basins of northeastern British Columbia.

Nexen said the partners will also investigate the feasibility of a potential downstream project—including liquefied natural gas (LNG) exports.

This is the latest of several deals involving Asian investment in Canadian gas or the possibility of shipping cheap western Canadian gas to Asian markets, or both.

Of the potential export projects, the most advanced is the ongoing study by gas producers Encana Corporation, Apache Corporation and EOG Resources, Inc. to build an LNG liquefaction plant at Kitimat, B.C.

Under the deal, Nexen agreed to sell a 40 per cent working interest in its northeastern B.C. assets for $700 mil-lion and will remain the operator. Half of the price will be paid at the outset and

the rest will be capital carry, Nexen said. Nexen would hold a 60 per cent interest in the joint-venture lands, and the other 40 per cent would be owned through INPEX Gas British Columbia Ltd., which has been jointly established by INPEX (82 per cent) and Japanese engineering firm JGC Corporation (18 per cent).

“The transaction provides us with world-class partners that have significant upstream and LNG expertise,” Nexen pres-ident and chief executive officer Marvin Romanow said in a press release.

Depending on economic conditions, the partnership will appraise and develop the resource after the deal closes. The 18-well pad Nexen is currently drilling is expected to be completed in the fourth quarter of 2012, increasing gross production volumes

to peak rates of about 155 million cubic feet a day in early 2013.

On a gross basis, the joint-venture lands are estimated to contain between four trillion and 15 trillion cubic feet of recoverable contingent resource in the Horn River and Cordova basins, and a fur-ther five trillion to 23 trillion cubic feet of

prospective resource in the Liard basin, Nexen said.

INPEX currently has 71 oil and gas projects in 26 countries, making it Japan’s biggest oil and gas exploration and pro-duction company. It has exploration, development and production activities around the globe with production of more than 400,000 barrels of oil equivalent, Nexen said.


Nexen strikes deal for B.C. shale gas development

On a gross basis, the joint-venture lands are estimated to contain between four trillion and 15 trillion cubic feet of recoverable contingent resource in the horn River and Cordova basins....

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NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

Bellamont Exploration is the latest to report success drilling Montney oil wells in northwestern Alberta.

Bellamont to target Montney oil in 2012

DEC/10 DEC/11


DEC/10 DEC/11

WELLS SPuDDED 230 247 ▲

DEC/10 DEC/11



scope as the Triassic D pool. Currently, Bellamont is producing approximately 535 barrels equivalent per day (490 barrels per day of crude oil) from the Triassic D Pool from 11 wells (10 hori-zontal wells and one vert ical). The company expects to develop the new pool with multistage fractured hori-zontal wells in a similar manner as the Triassic D pool.

“The delineation wells’ results have reinforced the corporation’s confidence in its ability to image reservoir-quality Montney sand on its three-dimensional seismic,” Bellamont said. “Based on the recent delineation dril l ing, core analysis and reservoir modelling, the cor porat ion now est imates its land at Grimshaw contains approximately 110 million barrels of discovered petroleum initially in place in the Montney formation.”

In total, when combining the exist-ing Triassic D pool and the new pool discovery, Bellamont estimates it has 52 hor izontal dr i l l ing locat ions at Grimshaw, all of which are supported by 3-D seismic.

Bellamont noted that it has also entered into an agreement to acquire a minorit y partner ’s interest in the Grimshaw area. The acquired asset consists of 13 (5.2 net) sections of land and includes a 25 per cent working interest in two joint Montney oil wells. Following closing of the acquisition, the company will have a 100 per cent working interest in 17 contiguous sec-tions of lands at Grimshaw.

The company said it recently under-took a reservoir simulation study of the Triassic D pool with Epic Consulting Services. The study supports a 10.5 per cent primary recovery factor based on eight horizontal wells per section, and a 19 per cent secondary recovery factor

Bel lamont Explorat ion Ltd.’s third-qua r te r f i n a nc ia l a nd pr o duc t ion results were relatively f lat year-over-year; however, the company said it recently made a Montney oil pool dis-covery at Grimshaw.

Bellamont said it recently drilled t wo v e r t ic a l we l l s (1.75 ne t) at Grimshaw to delineate the western por-tion of the Grimshaw Triassic D pool.

“The company is pleased to report the delineation program has resulted in a new Montney oil pool discovery,” Bellamont said in its third-quarter release.

In addit ion, both of the vert ical delineation wells encountered the same Mont ney reser voir sand producing in the Triassic D pool (the Montney D sand). Bellamont completed and tested the Montney D sand in one of the wells, which resulted in trace amounts of oil together with formation water. The

second well has yet to be tested in the Montney D sand.

The new pool discovery well was completed with a single five-tonne frac-ture stimulation. During the 26 hours of swabbing, the well tested an aver-age of 140 barrels per day of 29-degree API oil with less than 10 per cent water cut at the end of the test. This produc-tion test result is similar to Bellamont’s original vertical well discovery in the Triassic D pool.

The company has initiated the process of tying in the well to its 100 per cent–owned oil batter y, with production expected in the first quarter of 2012 at an initial rate of approximately 60 bar-rels per day.

Based on Bellamont’s interpretation of 3-D seismic over its lands, the company believes the new Montney oil pool has the potential of being similar in size and


Northwestern Alberta/Foothills

L one P i ne Re s ou r ce s I nc . c ont i n-ues building production at its Evi oil play, while focused northward for future growth.

In September, the company became independent, having been spun off from former majority-owner Forest Oil Corporation, a change management expects to “resolve capital expenditure constraints” that earlier kept the junior from pursuing certain business strategies.

In an operational update from the fourth quarter to date, released at the

end of November, the company said it had drilled nine wells at Evi with a 100 per cent success rate and had com-pleted and brought on stream eight (eight net) wells. Lone Pine has had considerable success in the second half of the year in decreasing the drilling time of its Evi wells. As a result of this improved operational efficiency, the company was drilling the last two of its previously planned 42 net wells.

Based on the early completion of its planned 2011 Evi drilling program, Lone Pine had increased its 2011 capital budget to US$250 million to US$260 million.

The increase in the capital budget will be allocated to Evi light oil drilling, where the company planned to drill up to an additional eight net wells prior to year-end. The increased capital will accelerate the company’s first quarter of 2012 capital spending and it is not expected that any of the incremental wells will be completed and brought on stream until 2012.

In a conference call to discuss third-quarter results, company executives touched ver y brief ly on Lone Pine’s

operations in the Liard Basin, N.W.T., which they said were just winding up.

“We’re just wrapping up operations at Liard and are unable to comment on the results, due to land continuation dis-cussions we’re having with the [National Energy Board] at this time,” said David Anderson, Lone Pine’s president and chief executive officer. No further infor-mation on the topic was released.

Lone Pine holds about 61,000 net acres in the Liard Basin, much of it prospective for the Muskwa shale. The company’s website describes its acreage there as a “newly developing natural

gas shale play adjacent to the produc-ing Horn River Basin.” Management believes the Liard acreage is analo-gous to the Muskwa shale in the Horn River Basin.

In the third quarter of 2011, Lone Pine drilled 14 net horizontal light oil wells on its Evi light oil play, reporting 100 per cent success. As well, the junior completed and brought on stream 11 net horizontal wells. In al l, during the quarter, Lone Pine completed and brought on stream 22 net horizontal

wells with an average initial produc-tion rate of over 300 barrels per day, and 60-day average production rates of about 200 barrels per day.

Also in the third quarter, Lone Pine drilled one net vertical well and com-pleted three (2.5 net) other verticals in the Nikanassin resource play in the Narraway/Ojay area. After the end of the third quarter, the junior dril led another net vertical well. At Sept. 30, 2011, the company held about 192,504 (127,104 net) acres in the Nikanassin resource play.


Lone Pine looks north for growth

possible under waterf lood. The com-pany has applied for regulatory approval to initiate a pilot waterf lood project in 2012.

B e l l a m o n t ’s n e w M o n t n e y o i l pool discovery at Grimshaw adds to an already deep inventory of oil and l iquids-r ich projects. T he company estimates it has over 140 net drilling locations specifically targeting oil and

intends to continue focusing on these projects into 2012.

For the remainder of 2011, Bellamont expected to drill two more horizontal oil wells at Grimshaw. Completion of these two wells is not expected until the first quarter of 2012, with production fore-casted for February.

T he compa ny ex pec ts to under-take a robust drilling program in 2012

and plans to provide budget guidance early in the new year. Bellamont said it has secured, or is in the process of securing, drilling licences for another 10 wells at Grimshaw (Montney oil), two wells at Stoddart, B.C. (Baldonnel oil), and three wells at Grande Prairie, A lta. (Montney oi l and l iquids-r ich natural gas).


In the third quarter of 2011, lone Pine drilled 14 net horizontal light oil wells on its evi light oil play, reporting 100 per cent success.... lone Pine completed and brought on stream 22 net horizontal wells with an average initial production rate of over 300 barrels per day, and 60-day average production rates of about 200 barrels per day.

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NORTHEASTERN ALBERTA WELL ACTIVITY

Northeastern Alberta

DEC/10 DEC/11


DEC/10 DEC/11

WELLS SPuDDED 101 74 ▼

DEC/10 DEC/11



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Industry is doing a better job telling its environmental story, says Suncor's outgoing boss rick George, but it needs to continue working to solve environmental issues.

president and a member of the company’s board, effective immediately. He will assume the role of chief executive officer upon George’s retirement this May.

“We have an environmental impact, we recognize that, and our job is to be absolutely at the leading edge of best prac-tice, and I think that’s what you’ve been able to see us doing in terms of innovation and performance,” he said. “We’re seeing the results from that now.”

Asked for his post-retirement plans, George said that he’d stay involved in the oilpatch “both from a personal investment and a leadership viewpoint.

“It ’l l be with much smaller com-panies—you haven’t gotten totally rid of me,” he said. “I’m going to kind of go do some work on technology and some smaller companies.”

The pair were asked about a report that the Canadian government had dis-missed the Kyoto Protocol on climate change as a thing of the past, and the impacts this will have.

“They are looking for a system that would work and Environment Minister Peter Kent would sign on if all the industrialized and the developing countries would sign on, that’s what I heard him say,” George said.

“Our job is to minimize our impact on air, land and water at every single opportunity that we have, so it will not, in my opinion, change the direction or what we feel like is our job here in this industry.”

The oilsands faces many challenges and Rick George, outgoing chief executive officer of Suncor Energy Inc., stressed that industry needs to continue telling its story and delivering results on minimizing its environmental impacts.

“Obviously, the industry’s got lots of challenges and I know the pressure put on by the environmentalists,” he said following the announcement of his impending departure. “We’ve done a much better job as an industry over the last two years in terms of getting the facts out—not the rhetoric, the facts—about showing the rate of continuous improvement.

“As important as that is, the technol-ogy changes that you’re going to see in this industry in the next 10 years, both in the mining side and the in situ side and the land reclamation side of this industry, is going to be off the charts.”

George is retiring as chief executive officer of Suncor effective this May and will be replaced by Steve Williams, the company’s president and chief operating officer. George was appointed president and chief executive officer of Suncor in

1991 and remained in that role follow-ing the mega-merger with Petro-Canada roughly two years ago.

Williams, Suncor’s chief operating officer since 2007, was appointed as the

Oilsands needs to continue environmental progress, says outgoing Suncor bossBy Richard Macedo

“ the technology changes that you’re going to see in this industry in the next 10 years, both in the mining side and the in situ side and the land reclamation side of this industry, is going to be off the charts.”

— Rick George, retiring president and chief executive officer, Suncor Energy Inc.



Cenovus Energy Inc.’s 2012 oil-focused capital budget of between $3.1 billion and $3.4 billion is about 23 per cent higher than planned 2011 capital spending.

The company expects liquids output to jump about 21 per cent in 2012, to between 155,000 and 171,000 barrels per day from an estimated 135,000 barrels per day this year, thanks to production growth at Christina Lake, Foster Creek, Pelican Lake and south-ern Saskatchewan.

Christina Lake phases are ahead of sched-ule and Foster Creek future phases are going to be larger than anticipated, Brian Ferguson, president and chief executive officer, told the company’s Investor Day. “Pelican Lake development is progressing very well, our tight oil development in southern Saskatchewan is right on track and we continue to grow our oil production in southern Alberta.”

Cenovus expects Christina Lake oil-sands volumes to more than double, to

between 26,000 and 29,000 barrels per day net, in 2012, compared with 2011, mainly due to its newest expansion, Phase C, which is expected to reach full production mid-year. The next expansion at Christina Lake, Phase D, is now anticipated to start produc-ing by the end of 2012, several months earlier than initially scheduled.

Ferguson told investors the com-pany is well on its way to achieving its 2011 guidance.

“We have consistently brought on new phases at both Foster Creek and Christina Lake ahead of schedule and under budget,” said Ferguson. “We now have eight SAGD [steam assisted gravity drain-age] phases that are operating and pro-ducing, and we have seven more phases that we have regulatory approval on.

“This basically accounts for all our oilsands growth for the next six years. We have all the approvals we need. The

CORE [coker and refinery] expansion at Wood River is up and running. That’s a major accomplishment and a major step forward on our integration strategy rela-tive to light-heavy differentials.”

The company anticipates being able to produce more oil at Foster Creek than initially planned as a result of innovation and improved efficiency. Cenovus has increased the combined gross production capacity of the next three Foster Creek phases, F, G and H, by 20,000 barrels per day. The improvement is due to increased output from its patented wedge well tech-nology combined with innovations in plant optimization that enable increased throughput.

Cenovus now expects Foster Creek to eventually reach gross production capacity of 290,000–310,000 barrels per day.

Pelican Lake is slated for higher oil volumes in 2012 due to its increased infill

Cenovus predicts major production bump

Husky Energy Inc. says the growth in its portfolio between now and 2016 will come from the oilsands and Asia Pacific, where it has substantial new production coming on stream.

The rest of the portfolio is broadly flat, Rob Peabody, chief operating officer, told the company’s Investor Day.

Sunrise Phase 1, slated for production of 60,000 barrels of bitumen per day (30,000 barrels net) and to cost about $2.5 billion, is on track and on budget, investors heard. Husky operates the oilsands project while its 50-50 partner, BP p.l.c., operates the refinery in Toledo, Ohio, where the bitu-men will be sent.

The steam to oi l rat io (SOR) is planned to be 3.0, with an initial SOR of 3.3–3.4, said John Myer, vice-president of oilsands.

Enhancements to get to an SOR of 3.0 include the placement of the steam assisted gravity drainage (SAGD) wells, said Myer. Sunrise has one of the high-est stratigraphic core well densities in

the industry, which gives the company certainty around geological mapping, he said.

Also, it will use measurement while drilling and low-pressure/low-tempera-ture SAGD, he added. “This is one of the advantages of having some very high per- meabilities in this reservoir. We won’t have to heat the reservoir up as much and therefore we’ll use less steam.”

In addition, Sunrise’s horizontal wells will be placed closely together.

The project was fully sanctioned for 200,000 barrels per day in 2010, the first horizontal well was spudded in the first quarter of 2011 and major construction started mid-2011.

Half of the SAGD wells have been drilled and the company is more than 125 drilling days ahead of schedule, said Myer. Planning is underway for commis-sioning in the second half of 2013. First steam is planned for the fourth quarter of 2013 and initial production is expected to start in 2014.

The company increased the 2012 budget at Sunrise to $610 million from an estimated $200 million this year as construction activity ramps up (Daily Oil Bulletin, Dec. 1, 2011).

Engineering is on schedule and final purchasing of equipment is nearly com-plete, investors heard. Construction of a 1,500-person camp is well underway and arrangements are in place for an aero-drome to fly workers in and out.

To help with cost certainty, lump-sum convertible and fixed-unit-price contracts make up about two-thirds of the total cost, said Myer.

Elsewhere in the company’s oilsands portfolio, this winter the company will drill some vertical wells at Saleski, its carbonates project, to determine the best position for its pilot wells, and will work on its field development plan scheduled for completion in 2012. It is working towards submission of a regulatory application for the pilot project in 2014.


Husky prioritizing Sunrise oilsands project



Hearing of escalating costs for labour, steel and other oilsands project components, Southern Pacific Resource Corp. says that, as with the first phase of STP-McKay, Phase 2 will be built in modules so small they can be shipped on trains from across North America and trucked on site.

Parts of Phase 1, a 12,000-barrel-per-day steam assisted gravity drainage (SAGD) project in Alberta’s Athabasca oilsands region, were built in Calgary, Edmonton, Saskatoon, Sask., Texas and

San Diego, Calif., and if Alberta “gets heated up again,” Phase 2 can be con-structed anywhere there are fabrication shops in eastern Canada or the United States, says Byron Lutes, president and chief executive officer.

“We’re trying to minimize the amount of people on site because that’s the expen-sive part,” he said. “There aren’t a whole lot of projects being constructed in 2012 and 2013, but after that it gets quite tight

again, so that’s where I’m fearful—2014 and beyond.”

The final design basis memorandum on costs for Phase 2 is expected around March or April, Lutes told the meeting.

Also to manage costs, Southern Pacific is compartmentalizing Phase 2 into two tranches of 12,000 barrels per day, he said. Phase 2B can be built after 2A using the same equipment and allowing some synergies. It also provides flexibility on financing, he added.

“If the world is very robust, we could potentially finance the whole project at once,” said Lutes. “If the world’s choppy and mixed like it is right now, we could either choose to build Phase 2A first or we could defer the entire phase until we feel more comfortable, so there’s no expiry date on the project once it ’s approved.”

The application for STP-McKay Phase 2, which is expected to add 24,000 barrels per

day of bitumen capacity, was prepared and submitted on November 10 to the Alberta Energy Resources Conservation Board and Alberta Environment and Water.

The application proposes to develop additional bitumen processing capacity on the eastern side of its existing project bound-aries, which would bring the total process-ing capacity to 36,000 barrels per day.

Southern Pacific continues to fore-cast substantial Phase 1 completion for the first quarter of calendar 2012, first

steam for the second-quarter calendar 2012 and first oil in the third quarter of calendar 2012.

Phase 1’s total cost is now expected to come in below the original $450-million budget at between $415 million and $440 million, including the addition of $15 million of scope changes that are expected to enhance the reliability of the plant and reduce operating costs.


Southern Pacific cuts SAGD costs by building off site

drilling and the expansion of the polymer enhanced oil recovery program.

Ferguson said Cenovus’ expected oil production growth for next year places the company well on the way to achieving its target of 500,000 barrels per day of net oil production by the end of 2021.

The COR E project at the Wood River ref iner y, jointly owned with ConocoPhillips Company, was recently completed and the 65,000-barrel-per-day coker is now operating. The US$3.8-billion project increases the refinery’s crude capacity by 50,000 barrels per day, enhances its ability to process heavy Canadian crude oil and improves its clean-product yield,

resulting in an increase in gasoline and distillate production capacity.

While the CORE project is expected to improve operating cash flow from the Wood River refinery in the long term, over-all refining operating cash flow for 2012 is forecast to be less than 2011 due to lower anticipated crack spreads and a tighter light-heavy differential. Cenovus contin-ues to benefit from its integrated business model since ownership of both refiner-ies and upstream production reduces the impact of market volatility on the company.

The company is working on more than 140 technology development projects and has set a goal of commercializing at

least one of these new technologies every year. In 2011, Cenovus commercialized its blowdown boiler technology, which is used to create steam at its oilsands plants. Blowdown boilers enhance efficiency by increasing the water recycle rate. This leads to fuel savings and a reduction in emissions and water use.

Cenovus began testing this technol-ogy at its Foster Creek facility in 2007. Blowdown boilers are in the plans for expansion phases now under construction at Foster Creek, and are being considered for use at the company’s other oilsands expansions and new projects.


“ We’re trying to minimize the amount of people on site because that’s the expensive part. there aren’t a whole lot of projects being constructed in 2012 and 2013, but after that it gets quite tight again, so that’s where I’m fearful—2014 and beyond.”

— Byron Lutes, president and chief executive officer, Southern Pacific Resource Corp.

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CENTRAL ALBERTA WELL ACTIVITY

Over $1 billion was invested in drilling rights in the Duvernay in 2011. Drilling will begin in earnest this year.

Sedimentary environments duringDuvernay deposition and rock lithology

Leduc reef outline

Peace River Arch edge of deposition

Woodband zero edge

Organic-rich shale (prospective shale)

Organic-poor shale (non-prospective shale)

Dolostone

Dolostone and evapourites

Sandstone and dolostone

Limestones

Conventional oil field

Conventional gas field

central Alberta

DEC/10 DEC/11

WELL LICENCES 288 290 ▲

DEC/10 DEC/11


DEC/10 DEC/11

WELLS DrILLED 267 153 ▼


Heavy producer interest in the Duvernay shale play in Alberta was a major reason the provincial government’s land sale coffers enjoyed a record cash infusion in 2011.

But with the most prospective land in the emerging play now spoken for, the industry is starting down a path of proving up the Duvernay, which has the potential to produce oil and liquids-rich gas. Many of the larger producers that spent hundreds of millions tying up land have already announced plans to begin punching holes into the play in 2012. Some have already started drilling.

The Duvernay was largely responsible for Alberta establishing a new record for bonus revenue at a single land sale June 1 when a massive $843 million was spent. Another large sale also driven by Duvernay interest was the $464.06-million auction on August 24.

But land sales tapered off in the final quarter of the year after a scorching summer of bonus revenue.

“What I’m quite sure I would find is the Duvernay rights have been tied up in the very most prospective areas of the basin now,” said Brad Hayes, president of Petrel Robertson Consulting Ltd. “People are now picking up bits and pieces to…con-solidate their positions and kind of clean up around the edges.

“There may still be some areas of the basin where the regional mapping says maybe it’s immature and it’s not going to generate hydrocarbons, and somebody’s got an idea that maybe that’s not quite right and so they’ll buy a few sections in there, then maybe they’ll drill a well [and] do a bit of testing.”

According to a report by Macquarie Securities Group released earlier in 2011, the Devonian-aged Duvernay shales are

considered a major source rock for a number of Upper Devonian Alberta oil and gas pools, which include the prolific Leduc/Slave Point/Keg River reef and pinnacle pools. Total organic carbon content in some areas is up to 20 per cent, which is a key indicator of hydrocarbon generation potential.

The Duvernay formation itself can be generally segregated into the base, middle and upper members: the base or lower member is a 20-metre-thick black argil-laceous limestone, the middle member is generally a black shale consisting of skel-etal reefal debris and the upper sequence is considered to be a brown bituminous shale/argillaceous limestone with thick-ness greater than 20 metres.

“We believe the base and middle mem-bers will ultimately be the most prospective target of the Duvernay formation, given the skeletal reefal debris [carbonate layers] contained within,” the report stated.

“It’s been studied a lot over the years as a source rock so it’s very organic-rich,” Hayes said. “It’s mature for oil up the middle of the basin and it’s mature for gas, deeper and hotter, in the western side of the basin.

“I think what’s still really being worked out is how much liquid can you get out of it,” he added. “We know that it’s going to produce a bunch of gas, we know it’s going to have some amount of liquids content.”

Producers will now likely want to establish the exact characterization of the reservoir in their particular area and determine how to make it work. They’ll also have to figure out an optimal hori-zontal length and decide which part of the formation to penetrate.

“Producers need to work out exactly where you target your well, how far is the horizontal, how many fracs do you put in, what chemistry do you put in your frac fluids,” Hayes said. “I think what they want to do in their particular area is they want to optimize the development treatment.

Producers to focus on drilling DuvernayBy Richard Macedo


central Alberta

With an initial capital budget of $180 mil-lion, Bellatrix Exploration Ltd. will con-tinue to be active in 2012, drilling its two core resource plays—Cardium oil and Notikewin condensate-rich gas.

In addition, the company currently plans to drill its first horizontal well in the emerging Duvernay play in the first quar-ter of 2012.

Based on the timing of proposed expenditures, downtime for anticipated

plant turnarounds and normal production declines, execution of the 2012 budget is anticipated to provide average daily pro-duction of approximately 16,500 barrels of oil equivalent per day to 17,000 barrels per day with an exit rate of approximately 18,000–18,500 barrels per day.

Third-quarter production was up 30 per cent to an average of 11,838 bar-rels per day from 9,119 barrels per day in the 2010 period, despite a protracted wet

spring breakup with road bans into mid-August in west-central Alberta, resulting in delays to the second-half drilling program. Sales volumes in the quarter were weighted 37 per cent to crude oil, condensate and natural gas liquids, up from 26 per cent in the third quarter of 2010.

Field production volumes for the month of October 2011 averaged approxi-mately 12,700 barrels equivalent per day, weighted 40 per cent to oil and natural

“Over time…they’ll decrease and opti-mize their drilling costs and they’ll get the best bang for their buck.”

Several of the larger players in Canada have slowly announced their Duvernay land acquisitions and have also started to discuss drilling plans.

Talisman Energy Inc. noted in a November presentation that it holds 184,000 net acres in what was referred to as the North Duvernay, with two pilot wells planned in the fourth quarter, and

in the South Duvernay the company holds 176,000 net acres with pilot wells planned in 2012, although an exact number was not provided. The company announced it picked up Duvernay acreage in Alberta in June for over US$500 million.

Enerplus Corporation holds 100 sec-tions of undeveloped land in the Duvernay and plans to drill a test well in 2012, while Encana Corporation said it planned to spud three Duvernay shale wells in the fourth quarter, two in the Willesden Green area and one at Simonette. The company holds about 365,000 net acres in what it believes to be some of the best liquids-rich acreage in the play.

Penn West Petroleum Ltd., mean-while, holds 100,000 acres prospective for the Duvernay.

“We have not stated publicly any plans for the speed of development,” said spokesman Jason Fleury.

The Duvernay, however, will likely be a difficult one for juniors, according to analysts, given the capital commitment required and risk associated with early stage plays.

David Reid, president and chief execu-tive officer of Delphi Energy Corp., said that, in general, the company is being both disciplined and patient with development

of its Duvernay acreage. Delphi has accu-mulated a large land position in the oil window at a low cost, along trend.

“We have conducted our own evalu-ation utilizing log data, Duvernay core data, DST [drill stem test] data and drill cuttings from older wells drilled through the Duvernay and believe there is a high probability of an economic oil window play developing over the next couple of years,” he said.

Delphi’s strategy, he said, continues to be to establish a land position early in these types of plays at a very low cost, then let larger industry competitors de-risk the play around its acreage.

“We believe this is the most cost- effective use of Delphi’s capital in this environment,” Reid said. “This strategy

has worked very well for us in the past, with examples of our NGL [natural gas liquids] plays in the Deep Basin Cretaceous zones [400 sections] over the past four years, and now on our Bigstone Montney acreage [45 sections] over the past 15 months.”

As for its Duvernay interest, at Sturgeon Lake (oil window) Delphi holds 108 gross (79 net) sections and at Bigstone (NGL rich gas window) six sec-tions at 100 per cent. There’s no field- capital spending planned for 2012, but

the company will continue with small capital in the lab “as deemed necessary.”

Can juniors make a go of it in the play?“Absolutely they can make this play

part of their portfolio,” Reid said. “Most importantly, it is about timing of expos-ing capital to the play. Preferentially, not until after initial operational and technical risks are reduced by larger competitors.”

He added that as the oil window play remains in its very early stages, the com-pany will keep all of its options open and be constantly evaluating its strategy as new data becomes available.

“Our view is that it has the potential to deliver high yields of NGLs as well as a positive outlook of a light oil play being economically developed,” Reid said.

Bellatrix sets $180M capital budget for 2012

“ Our view is that it has the potential to deliver high yields of nGls as well as a positive outlook of a light oil play being economically developed."

— David Reid, president and chief executive officer, Delphi Energy Corp.


central Alberta

With continued success on its Judy Creek Beaverhill Lake light oil play, Second Wave Petroleum Inc.’s corporate produc-tion based on field estimates has reached approximately 3,000 barrels of oil equiv-alent per day in mid-December.

Its Judy Creek Beaverhill Lake pro-duction exceeds 2,000 barrels per day (90 per cent light oil).

Second Wave has drilled, completed and brought on production 13 Beaverhill Lake hor-izontal oil wells in 2011, with an average pro-duction rate over the first 30-day test period exceeding 650 barrels per day per well.

The company built three separate Beaverhill Lake batteries in Judy Creek in the fourth quarter and was positioned to internally process all of its Beaverhill Lake emulsion by the end of 2011, which is expected to reduce operating costs on its Beaverhill Lake production base.

Through the fourth quarter, Second Wave has continued operating three

drilling rigs on its Beaverhill Lake drill-ing program. The company has spud-ded its 20th Beaverhill Lake horizontal well of 2011, with 13 wells completed and on production, four wells stand-ing waiting on completions and three wells currently drilling. Second Wave successfully completed five (2.6 net) Beaverhill Lake horizontal oil wells in the fourth quarter and expected to complete one (0.4 net) additional well prior to year-end to exit the year with three (1.2 net) horizontal oi l wells standing awaiting completion.

This year, Second Wave anticipates operating three to four Beaverhill Lake drilling rigs in Judy Creek and is well-positioned to meet its previously disclosed 2012 average and exit production guid-ance of 3,850 barrels equivalent per day (80 per cent oil and natural gas liquids) and 5,000 barrels per day, respectively.


gas liquids. In addition, Bellatrix has completed and tested four (2.7 net) wells, which are currently being tied in with an expected total initial production rate of 2,150 barrels per day.

Bellatrix spent $44.23 million on capital projects in the third quarter compared to $30.42 million in the third quarter of 2010, recording a 100 per cent success rate as it participated in 19 (13.41 net) wells resulting in 14 (10.97 net) Cardium oil wells and five (2.44 net) Notikewin/Falher gas wells.

The company said it continues to post above-industry-average initial produc-tion rates for Cardium wells, including two wells drilled in the second quar-ter and eight of the third-quarter 2011 Cardium wells that are on production. It achieved an average initial production of 566 barrels per day for the first seven days of production (10 wells), an aver-age initial production of 462 barrels per day for the first 15 days (10 wells), and an average initial production of 425 barrels per day for the first 30 days of production (seven wells).

At Ferrier, Bellatrix recently com-pleted two (gross and net) Cardium wells that produced condensate-rich gas on two fault-related blocks that occur along trend of its earlier Cardium oil discoveries. The new wells tested over a five-day period at six million cubic feet per day and 10 mil-lion cubic feet per day with 70 barrels per day of associated liquids yielding a total of 1,420 barrels equivalent per day and 2,367 barrels equivalent per day, respectively.

In the fourth quarter, Bellatrix planed to drill 12 (7.99 net) wells consisting of nine (7.04 net) Cardium oil wells and three (0.95 net) Notikewin condensate-rich gas wells.

For the first nine months of 2011, the company achieved 100 per cent drill bit success, drilling 42 (27.19 net) wells con-sisting of 31 (22.35 net) oil wells and 11 (4.84 net) liquids-rich gas wells.

Bellatrix has expanded its drilling inventory in its two key resource plays to 400 net locations in the Cardium light gravity oil play and 174 locations in the Notikewin condensate-rich gas resource play, yielding over $2.2 billion in future

development expenditures based on cur-rent costs of drilling. In addition, the com-pany now controls 44 (43 net) sections of Duvernay rights in west-central Alberta.

Year-to-date, Bellatrix has added 40 gross and net contiguous sections in the Ferrier area, which includes highly pro-spective Cardium and Duvernay mineral rights. During the first quarter of 2011, it entered into an agreement to acquire 20 net sections, and in August the com-pany added 20 gross and net contiguous sections in the area. At Sept. 30, 2011, Bellatrix had approximately 226,977 net undeveloped acres of land in Alberta, British Columbia and Saskatchewan.

As a key component of its strategy, Bellatrix has developed a company-wide infrastructure plan designed to position it as a leader for production growth in the core west-central Alberta area. Beginning 18 months ago, it committed to owner-ship in critical infrastructure that services Ferrier, Brazeau, Alder Flats, Willesden Green and the Greater Lodgepole areas.


Second Wave continues Judy Creek success

Second Wave is operating three drilling rigs in the Judy Creek area.

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SOUTHERN ALBERTA WELL ACTIVITY

Oil companies spent $3.64 billion at land sales in 2011. In 2012, the drilling will begin to prove whether the investment pans out.

DEC/10 DEC/11


DEC/10 DEC/11


DEC/10 DEC/11

WELLS DrILLED 330 108 ▼


Alberta put the icing on the cake of a record land sale year in December, attract-ing another $201.32 million in bonus bids, which included $55.69 million paid for oil-sands parcels.

The f inal sale of 2011 featured 203,059 hectares exchanging hands at an average of $991.44. The provin-cial government brought in an all-time record of $3.64 billion in bonus revenue this year on 4.6 million hectares at an average of $790.33.

The previous record of $3.43 billion in 2006—which seemed unbeatable just a few short years ago—was set due to heavy spending for oilsands acreage. The new watermark was reached because horizon-tal drilling and multistage hydraulic frac-turing are making it possible to develop previously uneconomic formations.

“Land sales illustrate that Alberta continues to be competitive in attracting

new investment, which benefits all Albertans,” Energy Minister Ted Morton said in a statement. “The technology being deployed to access these deep resource pools will translate into well-paying jobs, keep rural communities strong and contribute decades of royalty revenue to help fund health care, educa-tion, and other programs and services for all Albertans.”

Highlights of the December 14 sale included a bonus high bid of $58.96 mil-lion submitted by Scott Land & Lease Ltd. for a 7,360-hectare licence. The broker paid an average of $8,010 for the rights to several sections at 44-08W5, 43-08W5, 43-07W5 and 44-07W5.

“The…bid looks like Duvernay to me. The lands are in the Duvernay shale basin, the posting is large and there are a variety of deep rights posted, thus excluding the Cardium and most Deep Basin plays,” said

Brad Hayes, president of Petrel Robertson Consulting Ltd.

O & G Resource Group Ltd. paid $4.83 million for sections 33 and 34 at 61-19W5. The 512-hectare licence attracted an average bid of $9,430. The broker paid the same bonus and per-hectare amount for an adjacent 512- hectare parcel, which included sections nine and 11 at 62-19W5. The parcels were for petroleum and natural gas below the base of the Triassic system.

“They are likely for Duvernay, as well with companies just making sure all the highly prospective lands are addressed,” Hayes added.

Also at the sale, spending for oilsands acreage was revived with a $55.69-million haul, more than doubling what had been received year-to-date before the latest sale. This brought the 2011 oilsands land sale total to $104.68 million on 497,379 hectares. In 2010, the provincial govern-ment attracted $26.77 million in oilsands bonus revenue for 130,322 hectares.

Bidding under its own name, Laricina Energy Ltd. spent roughly $19.75 mil-lion on nine oilsands parcels in the area around 95-24W4, 95-25W4 and 96-25W4.

Glen Schmidt, president and chief executive officer, said these lands are contiguous to the company’s Burnt Lakes project. Laricina posted these lands when they became available.

“We are pleased with the develop-ments of our pilot at Saleski and the acquisition of these lands to augment our Burnt Lakes project,” he said. “This further enhances the scale of Burnt Lakes as our third core area.”

Windfall Resources Ltd. paid the highest price for an oilsands parcel with a successful bid of $17.15 million for a 7,424-hectare parcel, which included several sections at 92-20W4, 92-21W4,

Alberta enjoys record land sale yearBy Richard Macedo


Southern Alberta

92-22W4 and 93-22W4 for oilsands below the top of the Viking formation, to the base of the Woodbend group.

Looking ahead to Alberta land auc-tions in 2012, Hayes said land sale revenue will likely decline when compared to last year’s record tally.

“Much of the most prospective land on the unconventional resource plays we are aware of has been purchased and companies are faced with the drill-ing obligations to test and prove those lands,” he said. “They will likely be diverting more of their budget to drilling what they have, as opposed to adding to their land base.”

In 2012, there is still some land left to pick up on the margins of the resource plays and successful drilling results on any of these will motivate producers to spend more money on acreage now regarded as marginal, Hayes added.

“With sufficiently good results, we may see some resource play fairways expanded, with substantial bids on the new acreage,” he said.

“I’m not sure how much land might be reverting in 2012, but most of the resource play fairways are fairly well-known, so anyone about to have lands revert on those fairways is likely to drill them, or to find a partner to carry them in the drilling,” Hayes noted when asked about rights reversion. “I don’t see much good stuff reverting.”

Other resource plays are in the experi-mental stages and breakthroughs on those could inspire more spending.

“The Second White Specks and Nordegg plays come to mind, but I’m sure there are others that are less known,” he noted.

Geoff Ready, an oil and gas analyst with Haywood Securities Inc., said there seems to be some more Duvernay licences avail-able in the first few land sales of 2012.

“With new capital budgets, it will be interesting to see if this sets the tone for a continuation of the high-priced land grab in the play throughout the year,” he said. “More likely is that there will be a few more aggressively bid packages, but we will see a land purchase drop off in 2012 since the majority of the Tier 1 acreage has already been acquired.”

With continued weak natural gas prices, many bidders will have less cash flow and hence capital to work with in 2012, unless the markets pick up and equity financings flourish.

“There will definitely be more drill-ing to prove the [Duvernay] play up early

in the year, which could push future land prices in either direction, depending on results,” Ready said.

The Duvernay appears to be the driver for land sales early in 2012, but the market can shift quickly if solid results are found in other plays or as a change in technology dictates, he noted.

Ready added that shallow rights rever-sion won’t be an issue in 2012.

“The Energy Resources Conservation Board is starting to issue shallow expiry notices in 2011 for 500 land contracts every year [the first lot are from 1953 to 1958], and each company has three years to prove productivity from the shal-low zones before they will revert to the Crown,” he said. “Thus, the time frame is still a few years out and will only be a small land position each year. It will not have an impact in the short term.”

When asked whether there are any Duvernay-like plays on the horizon, Ready said that most of the large original oil in place and original gas in place reservoirs have been investigated for exploitation using horizontal multi-frac technology, “but there are always a few plays which slip through the cracks.”

“A breakout well or two in a play could open up a land rush in a new area, but I doubt there will be anything as really extensive as the Duvernay,” he noted. “You never know when a new technology opens up a new concept, though.”

Christine King, a spokeswoman with Alberta Energy, added that there is rights reversion every year (deeper rights cur-rently, shallow rights in 2014).

“This will put land back on the auc-tion block, but that doesn’t mean it immediately gets re-posted,” she said. “It can take time for the reverted lands to be re-sold. There is also land that will be returned to the land bank from

expiries—so not just reverted land, but the entire lease.”

As for new plays, companies have started to look at other possible opportunities beyond the Duvernay, King added.

“It would not be fair to those that have willingly discussed their plans with gov-ernment to share what we have been told, but there are certainly some emerging tar-gets that have been shared that look very promising,” she said.

Gary Leach, executive director of the Small Explorers & Producers Association of Canada, said that after the tremen-dous year in 2011 for Crown land sales in Alberta, it would be reasonable for the industry to take a breather in 2012.

“I would expect to see capital spend-ing shift towards drilling to better define the potential underlying the acquired leases,” he said. In 2010 and 2011, indus-try spent over $6 billion at Alberta Crown land sales.

“During 2012, there will be some par-cels that will attract premium bids, par-ticularly where the opportunity exists, to consolidate a position in a play as more information becomes available from drill-ing activity,” Leach added.

“ Much of the most prospective land on the unconventional resource plays we are aware of has been purchased and companies are faced with the drilling obligations to test and prove those lands. they will likely be diverting more of their budget to drilling what they have, as opposed to adding to their land base.”

— Brad Hayes, president, Petrel Robertson Consulting Ltd.


Southern Alberta

Drillers and pressure pumpers enjoyed a strong third quarter as operators ramped up play development using multi-frac hori-zontal wells, while midstream companies providing services to oilsands operators and producers pursuing crude oil and liquids-rich resource plays also benefitted from an uptick in industry activity.

For the three months ended Sept. 30, 2011, records show the largest year-over-year profit increases occurred at Trican Well Service Ltd. (up $57.95 million), Divestco Inc. (up $49.95 million) and Provident Energy Ltd. (a gain of $39.42 million from the third quarter of 2010).

Trican also booked the highest third-quarter profits ($111.26 million) out of 47 reporting companies tracked by sister publication Statistics Quarterly, fol-lowed by Precision Drilling Corporation ($83.47 million) and Inter Pipeline Fund ($76.56 million).

Seven companies—including Pembina Pipeline Corporation, Xtreme Coil Drilling Corp., Pulse Seismic Inc., Mullen Group Ltd., Veresen Inc., ShawCor Ltd. and Enerflex Ltd.—booked lower net income in 2011’s third quarter than in the year-prior quarter.

The largest net loss in the July-to-September period was reported by Enerflex ($37.3 million).

As a group, the 47 reporting companies that had released results by press time for Statistics Quarterly had a combined third-quarter profit of $788.22 million, up $354.67 million from $433.55 million in the comparable period last year.

Provident Energy had the largest year-over-year profit increase for the nine months ended September 30. The company’s net income rose to $76.63 million from a loss of $82.89 million in the first three quarters of 2010 (up $159.52 million).

Other companies reporting large increases in nine-month net income included Trican (up $129.01 million) and Precision (up $121.65 million).

Third-quarter cash flow for the com-panies rose $455.67 million to total $1.61 billion versus $1.15 billion in last year’s period. Over the first three quarters of this year, cash flow totalled $4.94 billion versus $4.158 billion in the January-to-September period in 2010.

Companies booking large increases in cash f low for the three months

ended Sept. 30, 2011, included Trican (up $67.2 million from the third quarter of 2010), Calfrac Well Services Ltd. (up $44.53 million), Ensign Energy Services Inc. (a gain of $37.53 million), Inter Pipeline Fund (up $34.38 million) and Pembina (up $26.13 million).

Nine-month revenues were also stron-ger, with the companies booking $21.7 bil-lion, up 32 per cent from $16.45 billion a year ago.

Improved pricing, larger fracture jobs, as well as higher horizontal drilling activ-ity, have helped underpin the revenue growth of companies offering fracturing and drilling services.

F i v e c o m p a n i e s posted a greater-than-$30 0 -m i l l ion ye a r-over-year jump in their nine-month revenues: Tr ican (up $571.36 million), Keyera Corp. (up $408.95 million), Calfrac (up $380.14 million), Precision (up $369.5 million) and Ensign (up $360.71 million).

For the three-month period, return on rev-enue (ROR, total profit divided by total rev-enue) was highest at Pason Systems Corp. (32.17 per cent).

Other companies enjoying a high ROR included Western Energy Services Corp. (30.81 per cent), Canyon Services Group Inc. (29.33 per cent), Inter Pipeline Fund (25.34 per cent), Total Energy Services Inc. (23.44 per cent) and Leader Energy Services Ltd. (22.17 per cent).

Capital spending for the nine months ended Sept. 30, 2011, totalled $4.94 bil-lion, up 103 per cent from $2.43 billion in the year-prior period.

In the first nine months, those compa-nies spending most in excess of cash flow were Ensign ($414.85 million), Essential Energ y Ser vices Ltd. ($163.66 mil-lion) and Secure Energy Services Inc. ($120.87 million).

Of the 47 companies tracked, all but nine increased their capital spending over the nine-month period of 2011 compared to the first nine months of 2010.

Over the year, service and supply companies have boosted their capital spending budgets: drillers are building new rigs, pressure pumpers are adding units and horsepower, and midstream companies are constructing new pipe-lines and facilities to handle liquids-rich gas and oilsands volumes.

In outlining their spending plans in late 2010 or earlier in 2011, 32 of the com-panies tracked had initially set a budget of $3.69 billion.

As of early December, that spending figure had ballooned by $1.14 billion to $4.83 billion.

Companies with large increases in budgets, in absolute dollar terms, are Precision (up $335 million from its ini-tial plans), Trican (up $305 million) and Savanna Energy Services Corp. (up $76 million).


Drillers, pressure pumpers enjoy strong third quarter

Service companies are reaping the benefits of technology-intensive drilling and completions strategies being used in unconventional plays.

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the Viking and Birdbear plays may drive land sales in 2012.

The Saskatchewan government ended the year with sharply lower land sales, although the province said there’s been a trend in the latter half of the year of companies concen-trating on working assets they’ve acquired.

In its final sale of the year, the oil-prone province took in $20.81 million in bonus bids on 41,653 hectares at an aver-age of $499.62. For 2011, Saskatchewan attracted $248.77 million in revenue on 504,395 hectares at an average of $493.21.

Last year, the provincial government took in $462.81 mill ion as 453,495 hectares exchanged hands at an average of $1,020.53.

Paul Mahnic, director of petroleum tenure with the ministry of energy and resources, said that while the Bakken in the southeast and the Lower Shaunavon in the southwest attracted the lion’s share of interest in 2011, accounting for two-thirds of land sale revenues this year, “it

was encouraging that the more traditional plays such as the Mannville heavy oil and Mississippian light and medium oil plays in the southeast continue to attract attention from industry.

“In the December sale, the dollars per hectare paid for land in the Lloydminster area actually exceeded that received in the south-east, evidence that heavy oil–prone lands are demanding a premium price,” he said.

In terms of land sales for 2012, industry will most likely continue with the expan-sion of both the Bakken and the Lower Shaunavon plays, and the narrowing dif-ferential bodes well for sales in the heavy oil area of the province, Mahnic noted.

“The resurgent Viking and Birdbear plays in the west-central area of Saskatchewan could raise some eyebrows in upcoming land sales as well,” he said.

Given the record numbers in terms of horizontal drilling this year, Mahnic said

it’s reasonable to assume that capital is being redirected from acquisition to drill-ing and exploration of the huge land inven-tories companies have amassed since 2007.

“The cyclical nature of industry in terms of evaluate [seismic, geological stud-ies], acquire, explore, drill, evaluate the results and acquire if warranted, naturally results in pauses as industry switches their attention from land sales to drilling or risks having leases expire, so fluctuations in land sale revenues are not unexpected,” he noted. “Further, the exceptionally wet spring this year delayed drilling programs, which would in turn have an impact on land sales as industry couldn’t evaluate lands for post-ing in sales.

“Saskatchewan is not immune to activity in neighbouring jurisdictions, and the record land sale year in Alberta would have most certainly redirected available capital that may have been ear-marked for Saskatchewan sales to Alberta as the land rush frenzy dominated land sales in the west.”

Don Rawson, managing director, insti-tutional equity research junior and mid-cap exploration and production, with AltaCorp Capital Inc., added that the highest prices for land in Saskatchewan over the past year seemed to be focused on Shaunavon acre-age and Bakken in the Flat Lake area.

“The Bakken play at Viewfield would be already locked up, but there is some southeast Saskatchewan land being acquired where producers are testing Bakken concepts outside of Viewfield,” he said. “The Shaunavon would be similar, although in some cases improvements in technology cause producers to reinterpret the perceived play boundaries over time.”

At the December land sale, the top pur-chaser of acreage in the province was Prairie Land & Investment Services Ltd., which spent $2.76 million to acquire 23 lease par-cels and two exploration licences.

Bakken, Shaunavon land sale hot spots in 2011By Richard Macedo

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Saskatchewan

Third-party research has confirmed that the CO2 used for enhanced oil recovery at Cenovus Energy Inc.’s Weyburn, Sask., oper-ation is not linked to CO2 concentrations in the soil at a nearby property, the company said in December.

The results provide complete assurance to landowners and the public that the CO2

the company is injecting about 1.5 kilometres below the ground is staying put and that its Weyburn operation is safe, Brad Small, Cenovus vice-president, oil and natural gas, Saskatchewan, said in a news release.

“Most importantly, it reconfirms what we already knew, which was that our CO2 is being contained in the reservoir rock and this study work, which had a lot more rigour and a lot more scientific method-ology applied to it, gave us the ability to definitively confirm that the CO2 in our reservoir is staying in the reservoir,” Small said in a conference call to discuss the results of the study.

“This is something that we’ve always known through additional study work that’s been ongoing for over a decade with the International Energy Agency and the British Geological Survey, as well as the input of about 30 different countries and their expert scientists,” he added.

Cenovus, which operates the Weyburn unit on behalf of 23 other partners, made a commitment to the Saskatchewan min-istry of energy and resources to evaluate whether CO2 in the soil and other reported issues at a nearby property were a result of its operations.

Nearby residents Cameron and Jane Kerr at a news conference early last year in Regina had demanded a full public investigation of problems at their farm

near Cenovus’ carbon capture and storage site. The Kerrs said they had first noticed changes in surface water and well water on their property in 2004, one year after CO2 injection in the area had begun (Daily Oil Bulletin, Jan. 19, 2011).

Several third-party specialists were contracted to conduct a site assessment.

“Our findings indicate that there is abso-lutely no way CO2 in the soil at the prop-erty in question originated from Cenovus’ operation in Weyburn,” said Court Sandau, founder of Chemistry Matters and lead sci-entist for the site assessment.

“Using isotope dating, we can dif-ferentiate between ‘young’ and ‘old’ carbon samples,” said Sandau, who has a PhD in analytical chemistry. “The CO2 that Cenovus injects comes from coal deposits, which were formed millions of years ago. Our findings assert that the CO2 present at the property was formed recently and is attributed to natural soil respiration processes.”

Findings of the comprehensive assess-ment confirm there is no presence of CO2 from Cenovus’ Weyburn operation in either the soil or wetlands of the property, there are no detectable hydrocarbons present in the surface water at the property, and there are no integrity issues with the Cenovus-operated wells and infrastructure on the property.

“We always take landowner concerns about our operations seriously and we felt it was important to commission this addi-tional study to address this concern,” said Small. “We are proud of the work that our Weyburn team has done and their efforts to ensure we are a good neighbour. We look forward to being a member of that community for many years to come.”

The scope of the assessment included the evaluation of gas concentrations in the soil at both the property and a con-trol site, characterization of the CO2 that Cenovus injects and the CO2 found in the soil, surface and groundwater testing, and integrity inspection of the oilfield infra-structure in the area. The full reports are available at www.cenovus.com.

“We did not detect any hydrocarbons when conducting surface-water sam-pling,” said Sandau. “Cyanobacteria and

phytoplankton were detected, which are common to relatively stagnant water bodies in southern Saskatchewan and are known to cause a ‘sheen’ on water surfaces, similar to what was initially reported on the water body.”

Cenovus also added a frog habitat and wetland evaluation after Northern Leopard frogs were found in the study area. “Frogs are sensitive to low levels of contamination. Their presence in the area is a strong indicator that a healthy eco- system is present,” said Sandau.

CO2 has been injected at the Weyburn unit since 2000. There are currently more than 17 million tonnes of CO2 stored at the Weyburn site.


Weyburn CO2 staying underground, says Cenovus

“Our findings indicate that there is absolutely no way CO2 in the soil at the property in question originated from Cenovus’ operation in Weyburn.”

— Court Sandau, lead scientist for Weyburn site assessment


Northern FrontierPh

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too much talk and not enough action may have killed the Mackenzie pipeline, says former transCanada boss Hal Kvisle.

Extreme regulatory delays that added $3 billion to the cost of the proposed Mackenzie pipeline may have killed the project’s prospects of being built, says the retired president and chief executive offi-cer of TransCanada Corporation.

The proposal to bring Arctic natural gas to southern markets, which failed to win regulatory approval in the 1970s, got the green light in December 2010 after one of the longest and costliest regulatory hearings in Canadian history.

“People talk about a $16-billion project—$8 billion of that was the pipeline project. That $8-billion pipeline would have been a $5-billion pipeline if the regu-latory process had not added $3 billion to the overall cost,” Hal Kvisle told the Standing Senate Committee on Energy, the Environment and Natural Resources in Calgary.

The one-day Calgary hearing was part of the committee’s nearly com-pleted cross-country tour to learn about challenges and opportunities faced by Canada’s energy sector.

Owners of the Mackenzie gas project are Imperial Oil Limited, ConocoPhillips

Company, Royal Dutch Shell plc, Exxon Mobil Corporation and the Aboriginal Pipeline Group.

Kvisle, who retired from TransCanada’s top job in June 2010, told the senators the

$3-billion cost escalation is one of three factors working against the pipeline because of the delay.

He said the second major hurdle is the risk that future gas discoveries won’t be enough to supplement the gas that has already been found. The project will initially tie in resources of three trillion cubic feet at Taglu, 1.8 trillion cubic feet at Parsons Lake and one trillion cubic feet at Niglintgak. All were discovered in the early 1970s.

Those resources aren’t enough to fill the pipeline for the 30-year life needed to make the project economic.

“But I think we all know once the pipe-line is in place, further drilling will follow—just as it has done in Alberta and B.C. and you would see that go. But that’s a problem when you expect the proponents of the project up front to take the risk that they or someone else will find enough gas to make it pay for the long term,” Kvisle said.

The third hurdle is that the massive amount of shale gas flooding the North American market is expected to depress prices for a long time.

“This has created a huge supply of gas here in western Canada that now means that the Mackenzie pipe would be bring-ing gas to a market that’s probably already oversupplied with gas,” Kvisle said. “And that’s going to be a big challenge. I do worry about the prospects for it.

“But to their credit, I know the people at Imperial Oil continue to work with the Government of Canada to try to find a way for that project to go ahead,” he added.

Imperial, the lead partner, and Ottawa have resumed talks over a financial sup-port package for the project.

David Emerson, chairman of the Energ y Policy Institute of Canada, which represents energy producers, said

Canada’s regulatory process is “nearly fatally flawed.”

“When you’re into the world of energy, you’re often talking about multi-billion dollar projects with hundreds of millions of dollars of revenue, and you’re asking private-sector people to put up this kind of resource com-mitment without knowing if you’re going to get an approval or when you’re going to get an approval, or even any indication as to its likelihood,” Emerson said.

“And it is just no way to become a global leader in this area that we believe is so fundamental to Canada’s economic future,” Emerson told the senators.

Red tape may have strangled Mackenzie gas prospects, says ex-CEOBy Pat Roche

“People talk about a $16-billion project—$8 billion of that was the pipeline project. that $8-billion pipeline would have been a $5-billion pipeline if the regulatory process had not added $3 billion to the overall cost.”

— Hal Kvisle, former president and chief executive officer, TransCanada Corporation

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Technology News

Insulation on demand

As energy costs continue to spiral upward, so does the demand for rigid polyurethane-type (PU) insulation for the oil and gas industry.

Producers, petrochemical companies and processors of all sorts have a con-t inuing need to insulate pipel ines, valves, electromechanical equipment and storage facilities in order to control temperatures. And when new pipelines or structures are under construction, there is usually a tight delivery window for insulation suppliers to provide the large volumes of materials that are often required.

“Those types of installation, whether offshore or at a processing plant, usually have firm delivery requirements,” says Daniel Desbiens, co-president and direc-tor of marketing at Pol R Enterprises, Inc., a Montreal-based distributor/fab-ricator that specializes in insulation products for commercial and indus-trial installations throughout eastern Canada. “They also require quality insulation products—such as pipeline, valve and equipment coverings—that are competitively priced, uniformly pre-cise in dimensional tolerances and are consistent in density,” he adds.

Oil, gas and petrochemical applica-tions often require miles of pipe insula-tion at a single installation. They usually require rigid insulation in specific shapes,

sizes and densities. To meet those require-ments quickly and efficiently, the fabri-cation of rigid insulation such as foam products has evolved into an automated production business that can satisfy cus-tomer delivery schedules on demand.

On-demand fabr icat ion of r ig id insulat ion for pipel ines and many other applications has resulted from advancements in the CNC-automated foam-cutting machines that enable fab-ricators to quickly and efficiently trim and shape a wide variety of foam-type materials, including the rigid PU, poly-isocyanurate (PIR) and Foamglas, as well as various mineral-fibre compositions.

“We transform foam-block products into customized insulation shapes for the petrochemical, offshore drilling and LNG [liquefied natural gas] industries,” Desbiens explains. “The automated foam-cutting equipment we have been using for the past four years has changed our busi-ness in terms of our ability to produce custom shapes much more quickly and accurately, improving productivity and reducing waste in the process.”

The equipment to which Desbiens refers is ProfileMatic, a CNC-based hori-zontal foam saw manufactured by Edge-Sweets Company (ESCO), a developer and manufacturer of PU fabrication and dispensing equipment based in Grand Rapids, Mich.

I n t he pa st fou r yea r s, Pol R Enterprises has acquired two of these sys-tems, which provide the firm with just-in-time efficiencies that were never before available to insulation fabricators. Both machines are dual wire, with both verti-cal and horizontal cutting (typically the vertical wire performs block trimming; the horizontal wire does top trimming and CNC profile cutting).

Eff icienc y and payback are also optimized when foam usage is max- imized by cutting in “nested” configurations. Nesting is achieved through system software that enables you to get multiple items out of a foam block or bun that might otherwise produce unnecessary waste.

“The nesting capability allows us to do two pieces at one cut,” says Desbiens. “This greatly affects the rapidity of work because we don’t have to do two cuts; you can do the outer layer and the inner layer of a shell at one pass.”

Although Pol R Enterprises primarily uses Foamglas and PIR foam for oil and gas insulation, the firm also cuts mineral- fibre shapes on the ESCO equipment.

Another powerful feature of ESCO’s nesting software is the ability to select common American Society for Testing and Materials (ASTM) pipe sizes directly from the HMI interface. This function-ality eliminates the need to draw each pipe size and joint type. Users select the desired pipe size from the predefined ASTM chart or custom data supplied by the customer, enter the quantity desired and click “nest.”

It is also possible to generate common cutting-line pipe profiles with ESCO’s Esco Draw Pro (advanced profile man-agement software), further adding to the system’s powerful suite of industrial pipe-insulation-generating tools.

Dean Seidler, fabrication manager at Crossroads C&I Distributors, the leading fabricator and distributor of commer-cial and industrial insulation products in Canada, says the ProfileMatic is ideal for cutting a variety of shapes out of Foamglas and other PU materials with a high degree of flexibility and accuracy.

“In addition to pipe coverings, we’re cut-ting a variety of rather complex insulation shapes for the oil and gas industry, such as an elliptical curve. So, when we’re doing elliptical vessel heads, we know we’ll get a true fit.”

As energy costs drive up the demand for insulation, automated profiling systems give insulation fabricators the ability to deliver customized pipeline and equipment coverings on a just-in-time basis.

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Technology News

Taking a lesson from other industries that treat their waste water on site rather than paying to transport and dispose of it else-where, gas producers are now employing mobile service providers armed with the latest integrated treatment systems (ITSs) to clean flowback and produced water from fracturing operations at the wellhead. This water can then be re-injected back into the well without fear of environmental harm.

This new business model can cut the average cost of treating produced water by as much as 50 per cent.

“Typically, drillers inject up to 600,000 gallons during the drilling operation and an additional 4.5 million gallons during the fracking operation. Approximately 20 per cent f lows right back out and needs to be treated,” says Eli Gruber, president and chief executive officer of Ecologix Environmental Systems, LLC, a provider of complete processed water and industrial waste-water treatment solu-tions. “Drillers are constantly seeking ways

Mobile on-site technology cuts cost of treating frac flowback water

to reduce their cost and at the same time maximize the quality of the effluent water.”

New innovations in treating produced water within a very small footprint have opened the door to bringing waste-water treatment to the source. ITS systems by Ecologix are pre-fabricated on movable skids or truck trailers with all the necessary controls, piping, valves, instrumentation, pumps, mixers and chemical injection modules. These mobile systems are now specifically designed to process flowback water from natural gas hydraulic fractur-ing or produced water from oil drilling wellheads.

The integrated treatment process begins by treating the water chemically with a coagulant, after which the water enters a series of coalescing tubes where solids join together and build increasingly larger polymer chains.

Accounting for the greatest gains in treating high volumes of waste water within a compact space is an innovative

process called air charged entrainment. Patent pending by Ecologix, this new gen-eration of water-treatment systems clarifies waste water through a process that mixes the waste water under high pressure with air and special chemistry, and then releases it all at atmospheric pressure in a basin.

As a result, suspended solids and other matter float immediately to the surface and can then be automatically removed from the system by a scraper mechanism. Additionally, any oil collected with the solids can be harvested for resale.

The clear water is then moved through one extra level of polishing with filters to remove any leftover solids.

One ITS unit can replace six to 12 settling tanks. An 18-wheeler deposits the ITS unit at the wellhead, pre-wired and pre-plumbed. Set-up proceeds quickly using standard cam-lock-style quick connects or American National Standards Institute flange connec-tions. Power comes from a mobile generator or site-provided power source.

Tax implications of expanding your business into the United States

BUSINESSINTELLIGENCE

By James Meadow, LL.M, MBAU.S. and cross-border tax partner, MNP LLP

Expanding your Canadian business into the United States can be excit-ing and rewarding. It can also be complicated—and costly—due to a number of tax implications you may not be aware of. Understanding the potential tax consequences of conducting business in the United States allows you to weigh your options ahead of time, so you can position your venture for success.

There are many ways of doing business in the United States. These range from carrying on business from a Canadian corporation that isn’t taxable in the United States, to a branch of the Canadian company that is taxable to a full-fledged U.S. subsidiary. Each of these alternatives brings with it its own tax consequences.

The Canada-U.S. tax treaty ensures that a Canadian company becomes subject to U.S. federal tax only if it has a “permanent establishment” or PE in the United States. If it has an office or fixed place of business in the United States, or is connected with a drilling rig or with a construction site that lasts for more than 12 months, it will have a PE and its U.S. business pro-fits will generally be taxed at the U.S. federal level at a rate of 34 per cent. It is also important for oilfield service companies to be aware that relatively recent changes to the tax treaty may affect them. According to the first of these new rules, if at least one Canadian employee of a Canadian company spends 183 days or more in the United States in any 12-month period, and the Canadian company derives more than half its active business revenue from the services performed by the employee or employees, then the Canadian company will be considered to have a U.S. PE and it will be tax-able. The second rule states: if a Canadian company performs services for an aggregate of 183 days or more in any 12-month period in connection with the same or a connected project, the Canadian company will be considered to have a taxable PE.

Many Canadian companies are aware that their Canadian employees can generally spend up to 182 days in the United States without becoming taxable in the United States. It is important to realize, however, that this means days of presence, which includes travel days, weekends and vacation days spent in the United States. In addition, this presence test now is based on any 12-month period rather than the calendar year. Moreover, there are two important exceptions to this general rule. If the Canadian company has a PE in the United States for any of the reasons explained above, or if the Canadian company charges back its U.S. subsidiary for those services, then the threshold under the U.S. domestic rules applies and the Canadian employee can only avoid becoming subject to U.S. federal tax if he or she spends less than 90 days in the United States during the calendar year and does not earn in excess of US$3,000 for services performed in the United

States. It is also important to note that many states have their own rules for state income taxation, which in many cases sets the threshold for becoming taxable quite low.

In most cases, the branch will also be subject to state income tax in one or more states at rates that vary from zero to approximately 10 per cent. In fact, it is not uncommon for a Canadian company to become subject to state income tax even if it isn’t taxable at the federal level, since most states do not follow the tax treaty. For example, most states seek to tax any company that owns any property or equipment present in the state or that performs any services within the state. Some states, such as Nevada and Wyoming, have no income tax. Others, such as Texas, have taxes more like a gross income tax with very few deductions. Still, others, like Oklahoma, have a capital tax or franchise tax in addition to an income tax. It is not usual for a company to be subject to income tax in more than one state. In that case, it becomes necessary for the company to allocate or “apportion” its income among those states according to the apportionment formulas of those states. Traditionally, most states used an apportionment formula based on sales, property and payroll. however, more recently, an increasing number of states have introduced formulas that emphasize the sales factor much more heavily than the other factors.

If a Canadian company rents equipment to a U.S. customer, the U.S. cus-tomer is supposed to withhold and remit federal tax of 10 per cent of the gross rental payments to the Internal Revenue Service. This is true even if the Canadian company rents the equipment to a U.S. subsidiary. In cases where day rates comprise both labour and equipment rental, determining the proper amount to be withheld may not be easy. The U.S. customer is required to obtain the proper withholding certificate from the Canadian company. The most common withholding certificates are the forms W-8BEN and W-8ECI. If the Canadian company fails to provide the proper withholding certificate, the U.S. customer is supposed to withhold 30 per cent of the payment. These rules also apply to a U.S. subsidiary transacting business with its Canadian parent corporation. If the Canadian oilfield services company incurs U.S. federal or state income tax, that tax should generally be creditable against the Canadian income tax attributable to that U.S. income. however, since U.S. corporate tax rates are higher than Canadian rates, there is typically a residual cost to being taxable in the United States. Over the years, as Canadian corporate tax rates have fallen, the gap between U.S. rates and Canadian rates has widened.

If the Canadian company establishes or acquires a U.S. subsidiary corpora-tion through which to carry on its U.S. business—perhaps in order to obtain lia-bility protection—the U.S. subsidiary will be fully taxable in the United States at both the federal and state levels.


BuSINESS ADVICE


ABB Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5Activated Environmental Solutions Inc. . . . . . .58Alberta Rig Mats . . . . . . . . . . . . . . . . . . . . . . . .58Annugas Compression Consulting Ltd . . . . . . . .6ASAP heating & Well Servicing Corp . . . . . . . . 16Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . .30Beijing zhenwei Exhibition Co, Ltd . . . . . . . . . . . 7Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . .22Bilton Welding and Manufacturing Ltd . . . . . . .22Brews Supply . . . . . . . . . . . . . . . . . . . . . . . 10 & 34Brother’s Specialized Coating Systems Ltd . . .33Brownlee LLP. . . . . . . . . . . . . . . . . . . . . . . . . . .58Canadian Standards Association . . . . . . . . . . .50Canwell Enviro-Industries Ltd . . . . . . . . . . . . . . 12Chemineer Inc . . . . . . . . . . . . . . . . . . . . . . . . . .30City of Grande Prairie . . . . . . . . . . . . . . . . . . . .26Clean harbors . . . . . . . . . . . . . . . . . . . . . . . . . . 25Compass Bending Ltd . . . . . . . . . . . . . . . . . . . 46Diversified Glycol Services Inc . . . . . . . . . . . . . 25dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Dragon Products . . . . . . . . . . . . . . . . . . . . . . . . 14DSI Thru-Tubing Inc . . . . . . . . . . . . . . . . . . . . . .32Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . .20EV Canada Inc . . . . . . . . . . . . . . . . . . . . . . . . . . 19Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . . . 18Government Communications and Public

Engagement. . . . . . . . . . . . . . . . . . . . . . . . . .42Infostat Systems . . . . . . . . . . . . . . . . . . . . . . . .24Joint Utilities Safety Team . . Outside back coverJoule Technical Sales Inc . . . . . . . . . . . . . . . . . .58London Business Conferences . . . . . . . . 38 & 54MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . 41Meridian Manufacturing Group. . . . . . . . . . . . . 17Minimal Impact . . . . . . . . . . . . . . . . . . . . . . . . . .9MNP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Nexus Exhibits Ltd. . . . . . . . . . . . . . . . . . . . . . .38Ocean Fluids & Filtration . . . . . . . . . . . . . . . . . . 25Petroleum Services Association of Canada . . . 41Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . 41Platinum Energy Services Corp. . . . . . . . . . . . . 21

Platinum Grover Int. Inc . . . . . . Inside front cover

Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . .3

RE/MAX Real Estate Central Alberta . . . . . . . .54

Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . 46

SMS Equipment Inc . . . . . . . . . . . . . . . . . . . . . .54

Southern Alberta Petroleum Show

. . . . . . . . . . . . . . . . . . . . . . . Inside back cover

Sprung Instant Structures. . . . . . . . . . . . . . . . .29

Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . .42

Tartan Controls Inc . . . . . . . . . . . . . . . . . . . . . .22

Trans Peace Construction (1987) Ltd. . . . . . . . .38

Vertigo Theatre Society . . . . . . . . . . . . . . . . . .50

V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . 13

Waydex Services LP . . . . . . . . . . . . . . . . . . . . . 37

Wildrose Alliance . . . . . . . . . . . . . . . . . . . . . . . .50

Advertisers' Index

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