Oil and Gas Inquirer October 2010

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Loosening HEAD the noose subhead British Columbia has a fix for wasteful, job-strangling government red tape.

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Will Alberta learn the lesson?

Head

Yea and nay Story Description

Enbridge’s $5.5B Northern Gateway Pipeline electrifies friends and foes

Head

Story Description

The upturn is coming — but when?

Pipeline contractors look toward an oilsands-fuelled recovery

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F E A T U R E S

6

OCTOBER 2010 • OIL & GAS INQUIRER

12

Loosening the noose

18

Waiting for the upturn

21

Yea and nay, big time

26

Tunnel vision

by Mike Byfield

British Columbia has a fix for wasteful, job-strangling government red tape. Will Alberta learn the lesson?

by Jim Bentein

Pipeline contractors expect an oilsands-fuelled recovery to take hold within two to three years

by Elsie Ross

Enbridge’s $5.5B Northern Gateway Pipeline sparks support and opposition

by Elsie Ross

Northern Gateway’s engineering calls for two massive tunnels

TCA provides engineered steel containment solutions for the Western Canadian Oil & Gas Industry R E G I O N A L

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N E W S

British Columbia

47

• Mitsubishi cuts $850M deal with Penn West for B.C. joint venture

intense resource-play development

• ARC defers some Dawson wells, planning

• PSAC still expects a 35 per cent

fourth gas plant

35

Northwestern Alberta • Peyto plans to drill 25 to 30 Deep Basin

increase in the 2010 well count

53

tight oil reserves in the West • Enbridge announces Bakken Pipeline

Basin drive Alberta sale

Northeastern Alberta • Oilsands spending flattens in 2010, but

Expansion Program

55

shale gas project in Quebec

• Suncor’s Firebag in situ expansion is on

43

Central Alberta

Central Canada • Questerre ramps up a commercial

planning accelerates schedule and on budget

Saskatchewan • Australia’s Molopo quietly builds up

horizontals by year’s end • Parcels in the northern region and Deep

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Southern Alberta • Service companies rebound due to

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International • A low-carbon fuel standard in the U.S.

• Horizontal rig release count soars to 224

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I N

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I S S U E

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Editor’s Note Vol. 22 No. 9 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com Publisher Agnes Zalewski | azalewski@junewarren-nickles.com Associate Publisher Chaz Osburn | cosburn@junewarren-nickles.com Editorial director Stephen Marsters | smarsters@junewarren-nickles.com

Mike Byfield | mbyfield@junewarren-nickles.com

EDITORIAL

Red tape blues

Editor

Mike Byfield | mbyfield@junewarren-nickles.com Editorial Assistance

Laura Blackwood, Marisa Kurlovich proofing@junewarren-nickles.com Contributors

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If you want to see an oil and gas manager tremble, make the suggestion that he criticize a government department or regulatory agency in the media or any other public forum.

That fear is entirely understandable. Provincial and federal civil servants can easily harass or even cripple a petroleum company, whether it’s a producer or a service operator. Applications can be queried or delayed, audits undertaken, hearings called, vehicles pulled over for inspection — the possibilities are virtually endless, and absolutely no rules would be broken.

This month’s cover story addresses red tape in Alberta’s oilpatch. It’s a tough topic to cover. On the record, even oil and gas associations do not help much when it comes to describing over-regulation. After all, their primary role is coordinating with government in crafting regulations — how many pounds per square inch will be permitted in gathering lines, what weight is allowed on which roads and when, how drillers should deal with the presence of an endangered species, and so on. Getting these details right is crucial to the industry. Inevitably, their associations usually avoid public arguments with civil servants of any class.

Here’s another problem: as regulations multiply, the private sector spawns companies that provide the services required to comply with those rules. Obvious examples would be soil treatment, emissions controls, safety training, etc. Those companies join industry associations. Naturally, trade association managers tread warily when addressing the regulations that underpin cash flow for a substantial portion of their members.

No one in his right mind is against government in principle. Strong laws are basic to any civilization, and efficient public administrators are worth their weight in gold. On the other hand, over-regulation chokes economies and strangles employment. Given the lack of effective criticism (along with very powerful unions in the public sector), the Alberta government has mushroomed far past its appropriate size, both overall and specifically with respect to energy regulation. In private, many petroleum executives are furious with the situation, as even Alberta politicians now admit.

Under Liberal Premier Gordon Campbell, British Columbia has emerged as Canada’s outstanding regulatory streamliner. As a reform-minded newcomer, the Saskatchewan Party’s Premier Brad Wall may well follow suit. Will Alberta remain competitive with its neighbours? Thankfully, the Energy Resources Conservation Board is putting its house in order, and the provincial government claims to be doing the same. Let’s hope they get it right. Otherwise, the Alberta Advantage will continue being hobbled by the supposedly pro-business Conservatives led by Premier Ed Stelmach.

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N E X T

I S S U E

Upcoming edition:

If you know an admirable person to profile in

In November, Oil & Gas Inquirer will look at

On The Job — he or she may be a veteran or

unconventional gas and conventional oil.

apprentice, field or shop, wise or a little crazy —

Actually, today’s crude prospects are mostly

please give me a call at (780) 944-9333, or

tight oil targets that require the same technology

email mbyfield@junewarren-nickles.com.

as unconventional gas! In November, we’re also

In fact, feel free to sound off about any

publishing British Columbia Focus, covering the

concern at all — that’s a personal invitation.

shale gas activity that has reshaped the patch.

OIL & GAS INQUIRER • OCTOBER 2010

9

Stats

FAST NUMBERS

250

AT A GLANCE

400,000

years

The life index of global natural gas supply that’s technically recoverable in the ground at today’s consumption rates, according to Royal Dutch Shell.

The number of households that Shell Canada can now supply from its increasing natural gas production from the Groundbirch area of British Columbia’s Montney play.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

TOTAL

Sept 2009 Oct 2009 Nov 2009

146 132 169

155 160 212

78 77 116

Dec 2009 Jan 2010 Feb 2010

121 253 144

127 324 308

Mar 2010 Apr 2010 May 2010

264 198 400

Jun 2010 Jul 2010 Aug 2010

126 131 168

MONTH

OIL

GAS

DRY

SERVICE

TOTAL

379 369 497

Sept 2009 Oct 2009 Nov 2009

146 331 382

155 196 244

45 32 68

9 12 10

355 571 704

35 62 114

283 639 566

Dec 2009 Jan 2010 Feb 2010

283 429 147

138 343 143

34 55 20

13 13 5

468 840 315

579 418 462

198 6 51

1,041 622 913

Mar 2010 Apr 2010 May 2010

548 291 490

681 458 511

109 2 39

20 9 19

1,358 760 1,059

117 110 135

41 38 43

284 279 346

Jun 2010 Jul 2010 Aug 2010

295 193 452

153 9 156

40 16 40

16 4 15

504 222 663

Wells Drilled In British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

homes

WELLS D R I L L E D

CUMULATIVE *

Sept 2009 Oct 2009 Nov 2009

38 29 39

Dec 2009 Jan 2010 Feb 2010

MONTH

OIL

GAS

OTHER

TOTAL

503 532 571

Sept 2009 Oct 2009 Nov 2009

194 157 171

7 5 11

3 7 10

204 169 192

45 65 101

616 65 166

Dec 2009 Jan 2010 Feb 2010

139 153 169

11 18 58

9 6 4

159 177 231

Mar 2010 Apr 2010 May 2010

98 56 54

264 320 374

Mar 2010 Apr 2010 May 2010

223 92 86

32 10 7

8 3 3

263 105 96

Jun 2010 Jul 2010 Aug 2010

41 65 30

415 480 510

Jun 2010 Jul 2010 Aug 2010

149 220 198

7 7 12

11 0 7

167 227 217

*From year to date

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OCTOBER 2010 • OIL & GAS INQUIRER

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S P O T P R I C E S at AECO trading hub in Alberta

GAS STOR AGE

Source: Natural Gas Exchange Inc.

Source: U.S. Energy Information Administration

3.75

in the United States

3.50

$3.61/GJ Total vol.: 1,686TJ Transactions: 206

3.25 3.27 Tcf Year ago: 3.45 Tcf 5-year avg: 3.07 Tcf

2.75

Aug 18

Aug 25

Sep 1

Sep 8

2.75

Sep 15

Cdn$/GJ

Aug 13

Aug 20

Aug 27

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada September 15, 2010 Source: Rig Locator

Alberta August 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE (Per cent of total)

Western Canada Alberta

208

335

543

38%

British Columbia

44

56

100

44%

Manitoba

12

8

20

60%

Saskatchewan

59

76

135

44%

323

475

798

40%

0

1

1

0%

WC Totals Northwest Territories

Sep 3

OIL WELLS

Alberta

GAS WELLS

Aug 10

Aug 09

Aug 10

Aug 09

Northwestern Alberta

146

98

70

28

Northeastern Alberta

78

66

0

0

Central Alberta

254

146

18

59

Southern Alberta

285

95

47

129

TOTAL

763

405

135

216

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada September 15, 2010 Source: Rig Locator

Alberta August 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE

Western Canada Alberta

COALBED METHANE

Alberta 336

316

652

52%

British Columbia

10

20

30

33%

Manitoba

14

0

14

100%

Saskatchewan

125

67

192

65%

WC Totals

485

403

888

55%

0

2

2

0%

Quebec

Sep 10

Tcf

BITUMEN WELLS

Aug 10

Aug 09

Aug 10

Aug 09

Northwestern Alberta

2

0

3

6

Northeastern Alberta

0

0

13

12

Central Alberta

0

45

52

30

Southern Alberta

0

11

0

0

TOTAL

2

56

68

48

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OIL & GAS INQUIRER • OCTOBER 2010

11

Loosen

by Mike Byfield Alberta is over-regulated to the point of killing many jobs, warns the Canadian Federation of Independent Business (CFIB). “Most Albertans strongly support the concept of lean, efficient regulation, but their province’s performance is among the most inefficient in the country,” says Laura Jones, western Canadian VP for the 107,000-member lobby group. “British Columbia has evolved into a model of streamlined regulation, and we have high hopes for Saskatchewan. However, our frustration with Alberta is beyond description — so far, its current initiative toward regulatory reform doesn’t amount to much more than window dressing.”

In March, the A lberta government published its Competitiveness Review, compiled over the previous year.

The review found that “the [energy] regulatory system currently in place in Alberta has become increasingly complex and is characterized by a lack of integrated policies and delivery mechanisms.” Alberta Energy Minister Ron Liepert acknowledges that he has “probably heard more about regulatory burden than I heard about anything else.”

In a closed-door meeting with the Canadian Association of Petroleum Producers (CAPP) and the Small Explorers and Producers Association of Canada earlier this year, provincial officials reportedly fielded more gripes about

12

OCTOBER 2010 • OIL & GAS INQUIRER

regulations than royalties. “At that point, people realized that Alberta’s royalty rates would come down, thanks to competition from B.C. and Saskatchewan for the same investment dollars. There’s a lot less confidence that the red tape burden will be reduced significantly,” recalls one oil company executive who requested that his name remain confidential.

Very much on the record is Jean-Michel Gires, president of Total E&P Canada Ltd. Its Paris-headquartered parent company plans to invest $15 billion to $20 billion over the next 10 years in oilsands projects. Gires, a former regulator with the French government, told the TD Newcrest Unconventional Oil and Gas Forum in Calgary on July 15 that Alberta’s regulatory scheme is “sophisticated” but cumbersome to the point of distraction.

“Our current estimation of meeting approval for a greenfield SAGD [stea m assisted g ravit y dra i nage] projec t would be something like three years and a new greenfield mine, like Joslyn, would be something like five years. Why do we need five years to get regulatory approval for a new mine

ing British Columbia has a fix

for wasteful, job-strangling government red tape.

Ill u

st

ra

t io

n:

Fr

ed

Cu

r a to

lo

Will Alberta learn the lesson?

OIL & GAS INQUIRER • OCTOBER 2010

13

when it is not really the first type of mine we are developing?”

Gires queried. “It’s pretty difficult to understand for me, so I’m very pleased that now the Alberta government...has started discussing streamlining such processes.”

Lawrence West, president of Orion Oil & Gas (North America) Ltd., thinks the regulatory overload is even more difficult for junior operators. “Incremental layers of regulation over many years and across many government departments has created an inefficient, complicated web of processes, resulting in greater complexity and higher compliance costs for industry,” West comments.

“Overall, the regulatory burden, especially to a small producer in a relatively proportional sense, is very high.”

unrealistic in the patch,” says the president of a substantial service company. “Let’s say someone is moving equipment up at Zama but a cat unexpectedly blocks the access road for several hours.

Even if that driver catches a nap, he’s working as far as Ottawa is concerned. If his hourly limit gets maxed out, he’s supposed to tell the client that its rig or whatever won’t arrive on schedule and its field crew will have to sit around while he sleeps. Yeah, right, that’s going to happen.”

Alberta’s restrictions are relatively liberal, permitting a driver to work up to 15 hours a day as long as he wishes. Even that limit irks drivers who know they’re capable of putting in a longer shift when necessary. Worse, the federal government is pressuring Alberta to bring its motor carrier rules into line with the national code. “Besides driver hours, trucking is subject to dozens and dozens of rules. Every time one of my guys has to pull over at a weigh station, he knows that the inspector on duty can always find something wrong if he’s a road predator,” says the company president. “Outsiders have no idea how wasteful it all is. Our productivity per driver has fallen by 70 per cent since the 1980s.”

A myriad of government departments and agencies help administer oil and gas, from self-evident players — energy and environment — to the esoteric, like heritage archeologists and human rights commissions. Alberta, following up on its

"Every time one of my guys has to pull over at a weigh station, he knows that the inspector on duty can always find something wrong if he’s a road predator."

Photo: Joey Podlubny

— Anonymous company president

Abandoning the Balzac plant will involve inter-agency streamlining.

In private, some petroleum service specialists offer harsher views, especially with respect to federally regulated oilfield transportation. “Everyone cheats when it comes to driving hours, or almost everyone. Otherwise, you couldn’t stay in business, the rules are unworkable,” claims one veteran manager who dispatches dozens of heavy vehicles across the three western provinces every month. Any truck-mounted equipment that crosses a provincial boundary must obtain a federal carrier authority. The feds restrict drivers to 70 working hours over 7 days or 120 hours over 14 days, followed respectively by 36 or 72 hours of mandatory time off.

“The restrictions may make sense for someone transporting fruit or refrigerators down the freeway, but they’re completely 14

OCTOBER 2010 • OIL & GAS INQUIRER

Competitiveness Review, passed the Alberta Competitiveness Act and launched the Alberta Competitiveness Council. The council is co-chaired by Premier Ed Stelmach and Alberta Economic Development Authority chair Bob Brawn, with Finance and Enterprise Minister Ted Morton as an alternate co-chair. This year, the new agency is reviewing the province’s competitive position in agriculture, petrochemicals and chemicals, financial services, and manufacturing.

Competitiveness, however, is a grab bag that extends far beyond regulation; its concerns range from taxation and infrastructure through to innovation and education. Taking a direct approach to oil and gas red tape, the province also appointed a Regulatory Enhancement Task Force to undertake a comprehensive streamlining of its energy rules. The task force is in the process of consulting with industry, landowner, municipal and environmental groups through a series of stakeholder sessions.

The task force should write its final recommendations by the end of this year. In mid-June, it released a 90-day progress report.

“We’ve made progress addressing costly inefficiencies in the current oil and gas regulatory system while maintaining Alberta’s high environmental standards,” said Diana McQueen, the Drayton Valley-Calmar MLA who chairs the initiative. Progress to date includes: • P ilot work towards a system of coordinated compliance inspections;

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• Successful streamlining of assessment submissions required prior to oilsands developments; • Simplification of subsurface well spacing requirements; • Improved access to information and regulations; • Clarification and simplification of regulatory publications; • Elimination of obsolete and expired regulatory publications; and • Harmonizing regulations with other provinces.

The task force has identified cost reductions that should benefit industry by $80 million to $170 million annually. That estimate comes from the Energy Resources Conservation Board (ERCB), which created its regulatory development branch a year ago. Cal Hill, executive manager of the new branch, says, “We are reducing complexity, cost and overlap between agencies. Also, Alberta has changed from being primarily a conventional oil and gas basin to more unconventional resources like bitumen, CBM [coalbed methane] and tight gas. Our regulations are being adjusted to fit these new purposes.”

For instance, subsurface well density is a critical issue for conventional gas reservoirs, to maximize ultimate recovery and to eliminate potential inequitable drainage of neighbouring reserves.

To address those concerns, the ERCB has specific subsurface well spacing requirements and application processes in place to optimize resource production and to ensure that operators have a fair opportunity to recover their reserves. Subsurface well spacing is often less of an issue in unconventional plays because gas doesn’t move easily through the rock. “With lower-permeability reservoir rock, recovery rates and adjacent drainage are normally not an issue, and wells are typically spaced more tightly to optimize production,” Hill says. “In large parts of Alberta, we can now reduce the number of new well spacing applications.”

16

OCTOBER 2010 • OIL & GAS INQUIRER

On the other hand, notes the branch executive manager, regulators now need data and regulations that are relevant to unconventional technologies like multi-stage horizontal fracturing and multi-well drilling from a single pad. “Alberta has long had one of the world’s best energy regulatory systems,” he comments, “and we’re adjusting our procedures and requirements to maintain a leading-edge position with respect to unconventional resources.”

Regulatory overlap is the target of a pilot project focused on abandonment of the Balzac Gas Plant. Normally, Alberta

In a recent membership survey, 26 per cent of CFIB business owners said that if they had known the burden of regulation, they may not have gone into business at all.

Environment and the ERCB would each pursue their responsibilities under separate rules and timelines. At Balzac, the two provincial entities will take a coordinated approach, which will hopefully reduce the number of plant visits, enable sharing of expertise and result in speedier decommissioning. Any lessons learned will then be applied more broadly to future abandonments.

Over the next three years, the ERCB plans to consolidate its interim directives, information letters and associated guides, and

to eliminate obsolete requirements. Since 2004, the regulatory agency has reduced the number of regulatory publications from 205 to 164. An additional 10 publications are in the process of being eliminated in the near term.

Laura Jones, an economist by training, applauds Alberta’s initiatives in principle. “Regulatory reform is the flavour of the year for governments across the country, and that’s fine as far as it goes,” says the CFIB VP, whose organization has about 10,000 member businesses in Alberta and an equal number in British Columbia. “Our concern is achieving measurable improvements and also maintaining long-term accountability. If we don’t put effective monitoring procedures in place, government bureaucracies will soon revert to their traditional wasteful ways.”

In 2005, the CFIB authored a report that pegged the business cost of compliance with government regulations at $33 billion annually. In an update released this year, the lobby group estimated that cost at $30.5 billion. “These are conservative, rockbottom figures. We’ve seen progress, but not much,” Jones says.

“Excessive regulation is a hidden tax that squanders resources which could otherwise be put to productive use. The amount of time spent filling out pointless forms is painfully obvious to business managers, but usually the waste remains invisible to most other people.”

In a recent membership survey, 26 per cent of CFIB business owners said that if they had known the burden of regulation, they may not have gone into business at all. “To me, that was truly shocking,” Jones says. Among the most discouraged are small businesses. Because all companies within an industry must comply with pretty much the same set of rules, the cost of compliance per employee is five times higher for the smallest outfits compared to

bigger firms. “Very often, the person dealing with the red tape is a business owner who’s already under stress and short of time for his or her family,” the CFIB VP says.

The poster child for red tape slashers is British Columbia, although Nova Scotia has become a challenger in recent years.

In 2001, the B.C. Liberals campaigned on a promise to reduce the regulatory load on their economically lagging province by at least one-third within three years. Upon winning the election, the new government created a Ministry of Deregulation, whose sole responsibility was reducing the bureaucratic load of government on business and people. “At this point, nearly 10 years later, the actual shrinkage in red tape has reached 43 per cent,” Jones says.

A crucial factor in British Columbia’s achievement, according to the Vancouver-based economist, was realistic benchmarking.

“Just counting regulations is meaningless. A single regulation can be associated with literally thousands of requirements that are imposed on businesses. The B.C. Liberals tracked those requirements. Since 2001, they’ve been reduced by 163,000 and the figure is still falling,” Jones explains. Nova Scotia took a different tack, counting the number of hours needed to comply with its regulations. So far, its regulatory streamlining has saved businesses 93,000 hours per year, a significant success in a small province.

“Regulatory compliance cost is not easy to quantify, and it actually makes sense to have several tracking measures,” Jones says. “We’ve had discussions with the Saskatchewan government, and its leadership seems to be sincerely committed to reform, including realistic measurement of results. Despite our best efforts, however, Alberta rejects regulatory benchmarking and the discipline of accountability. It’s a strange attitude for a provincial government that calls itself pro-business and Conservative.”

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17

WAITING

for the

upturn Pipeline contractors expect an oilsands-fuelled recovery to take hold within two to three years

by Jim Bentein

I

f you’re a pipeline construction company that specializes in building crosscountry lines, like O.J. Pipelines Canada, these are tough times, since there are no long-distance pipeline projects in the offing until 2012 or later. But if you’re a company like British Columbia’s Surerus Pipeline Inc., which specializes in shorter-distance pipelines and “inside-the-fence” lines that move product from one part of a plant site to another, business couldn’t be better.

18

OCTOBER 2010 • OIL & GAS INQUIRER

“Last year was our best year ever,” says Sean Surerus, project coordinator with 40-year-old Surerus. The pipeline and facilities construction firm has benefited from the boom in shale gas development in the Horn River and Montney areas of British Columbia, which it services from its Fort St. John base. “We feel we have a good three years [of work] ahead of us. If you look at the rig count in our area, it’s up a lot. Pipelines follow that,” says the son

Photo: Enbridge Inc.

While pipeliners trudge through a slump in trunk projects, shale gas activity benefits crews in B.C.

of company founder, president and CEO Brian Surerus.

“Last year, we had three significant projects in a row,” Sean Surerus reports.

That trio included two natural gas pipelines for Spectra Energy Corp., the largest gas transmission and processing firm in British Columbia (a 92-kilometre gas pipeline and three development drills) and a hydrogen pipeline in the Strathcona County area near Edmonton for Air Products and Chemical Inc., one of the world’s largest specialty gas producers.

Surerus said his firm, which peaked at about 500 employees on staff last year, recently bid on about 10 projects and hopes to win some contracts as a result.

The company operates in a sweet spot, he adds, with the capacity to handle “middle-sized projects” of medium- and large-inch pipe worth bet ween $20 million and $250 million.

“We have the financial capacity, personnel and equipment to do those kinds of jobs,” Surerus comments. “Once the project is worth $250 million and up, it gets very competitive.” In his view, being a privately owned company provides a competitive advantage over larger, publicly owned firms. “We don’t have committees,” Surerus says. “The buck stops at my dad.”

The near-term picture is grimmer for companies like O.J., which specializes in building cross-country pipelines.

By nature, this sector must routinely cope with lean periods. “It started slowing down last year, after the market fell [and the credit crisis hit] and it hasn’t improved much since. We’re at the tail end of the cycle and [major pipeline] projects require long lead times,” says David Kavanaugh, president of O.J.’s Canadian division. “From the time they get approved, it can take two or three years until construction actually starts on a long-distance pipeline.”

The most promising prospect is the Keystone Gulf Coast Expansion Project planned by TransCanada Corporation.

The initiative would substantially add to the existing Keystone system between Hardisty, Alta., and the U.S. Midwest, which went into commercial service in June. If all proposed Keystone expansions proceed on schedule, the completed system could deliver 1.1 million barrels per day along a route from Alberta to the Texas Gulf Coast, a massive refining region.

Tra nsCa nada st i l l requires U.S. appr ov a l f or t he 2 ,657-k i lomet r e Montana-to-Texas leg, which would t ra nspor t 435,000 ba r rels per day to Illinois. T he project is opposed by env ironmental groups and some politicians who resist the prospect of importing more bitumen from Alberta.

Ironically, TransCanada’s project also faces potential delay due to a pipeline rupture suffered in Michigan by its archrival Enbridge Inc. (Both pipeline companies are headquartered in Calgary.)

On July 26, a rupture on Enbridge’s Lakehead System spilled an estimated 19,500 barrels into the Kalamazoo River.

The incident, one of the worst pipeline leaks in the United States ever, happened to occur while oil spewed into the Gulf of Mexico from BP’s offshore blowout. Most analysts still expect Keystone to proceed, but public concern over crude oil accidents could lengthen the regulatory process.

When Keystone construction proceeds, TransCanada plans to first lay 700 kilometres of new pipe in Oklahoma and

project and TransCanada’s Keystone.

Kavanaugh says O.J. does have one project starting up in December, which involves a 100-kilometre, 24-inch pipeline. That will be a “three-seasons” job. Overall, he predicts, “it doesn’t look as if 2011 will be any better than this year. However, I expect things to pick up by 2012.”

Wi l lbros Ca nada, a d iv i sion of Willbros Group Inc., has weathered the dearth of major pipeline construction by finding other work. “The fact that we’re diversified helped get us through the slow period,” says Rob Sobchishin, its director of business development. The firm, based in Calgary, Edmonton and Fort McMurray, does engineering procurement and construction work on large projects and has been able to keep relatively busy in the oilsands. It also handles plant maintenance and has won several oilsands-related contracts.

The diversification strateg y also extends to its pipeline work. Willbros constructs both “inside-the-fence” and “outside-t he-fence” lines. T he f ir m

"It started slowing down last year, after the market fell… and it hasn’t improved much since. We’re at the tail end of the cycle and [major pipeline] projects require long lead times."

— David Kavanaugh, President, O.J. Pipelines Canada

Texas. This expansion phase is currently scheduled to start construction in the first quarter of 2011 and be complete by the fourth quarter of 2011. Construction of the following phase would include 526 kilometres of new pipe through Canada. The line would then extend south approximately 1,371 kilometres through Montana and South Dakota to Nebraska.

Construction of that phase is anticipated to be completed by the first quarter of 2013.

Further into the future is the proposed $5.4-billion Enbridge Northern Gateway oilsands pipeline from near Edmonton to tidewater at Kitimat, B.C. However, that project must address substantial opposition from First Nations, green lobbyists and others. (See articles on pages 21 and 26.)

O.J. and other long-distance pipeline contractors were intensely busy during 2006–07, working on the Enbridge Clipper

recently picked up two contracts, both in northern Alberta. It will build a 12-inch, 420-kilometre line from Fort McMurray to the Redwater Olefins Plant, near Edmonton. Also, the company has been hired to construct six pump stations for the Pembina Pipeline Corp. Nipisi Pipeline, which will carry 100,000 barrels per day of diluted heavy crude from Slave Lake to Judy Creek, Alta. Contract values haven’t been made public.

Willbros employs 300 to 400 workers on a steady basis, with those numbers increasing when it wins a major project. “Things [in the pipeline sector] are definitely starting to improve,” says Sobchishin. That improvement stems mainly from an activity recovery in the oilsands sector. “The way it’s looking now,” he comments, “there will be a steady improvement, with things picking up in 2012 and 2013.”

OIL & GAS INQUIRER • OCTOBER 2010

19

Feature Illustration: Enbridge Inc.

The Enbridge plan calls for two pipelines, one carrying export oil and the other imported condensate.

Yea and nay, big time Enbridge’s $5.5B Northern Gateway Pipeline sparks support and opposition

by Elsie Ross

A

t $5.54 billion, Enbridge Inc.’s proposed Northern Gateway crude oil pipeline project could be the largest private-sector project in B.C. history, but it could also be among the most divisive. The project is already pitting northern communities desperate for an economic boost and an Alberta oilsands industry looking for new markets against a powerful coalition of First Nations and environmental groups.

The most vocal supporter of the project has been the Northern Gateway Alliance, a group of businesses and local governments British Columbia’s north coast who see the economic benefits of the project for an area whose economy has been devastated by the decline in the softwood lumber industry.

While the oil industry believes there is merit in a pipeline that would diversify oilsands markets into the Asia-Pacific region, currently, no producers have been prepared to sign up for transportation capacity. Pipeline competitor Kinder Morgan Canada, which has its own proposal for new and expanded markets to the West Coast for Alberta oilsands bitumen, will likely oppose the Enbridge plan through the regulatory process.

An even more significant uncertainty is posed by aboriginal rights, which have never been extinguished by treaty in most of British Columbia. At the very least, First Nations could likely tie up the Northern Gateway project for years through court challenges. There have been general dis-

cussions between the Northern Gateway Pipelines Limited Partnership and First Nations about taking an equity interest in the pipeline, according to Enbridge spokesman Alan Roth. This fall, he says, the company will be communicating more detailed information on the scope and benefits for aboriginal groups.

If built, Northern Gateway will generate big benefits for the economy as a whole.

Enbridge anticipates that approximately 62,700 person-years of employment will be created over a three-year construction phase with 3,000 direct on-site workers required during the peak period of construction. It also will provide about 1,150 long-term job opportunities throughout the Canadian economy, including OIL & GAS INQUIRER • OCTOBER 2010

21

Illustration: Enbridge Inc.

Environmentalists oppose both Enbridge's trans-Rockies route and increased tanker traffic on the West Coast.

104 permanent operating positions with Northern Gateway and 113 positions with the associated marine services.

The project would contribute a total of approximately $2.6 billion in local, provincial and federal government tax revenues, including an estimated $36 million per year in local property taxes over the 30-year life of the project. Canadian gross domestic product would increase by $270 billion and additional labour income would be $48 billion as a result of an additional 558,000 person-years of employment.

Federal and provincial governments would collect an additional $81 billion.

22

OCTOBER 2010 • OIL & GAS INQUIRER

At Enbridge’s annual meeting earlier this year, CEO Pat Daniel acknowledged that while his company had anticipated opposition to the project to the West Coast, “we didn’t expect it to be as strong at it is.” And that was before a rupture in a pipeline operated by affiliate Enbridge Energy Partners spilled 19,500 barrels of crude into the Kalamazoo River in Michigan.

Later this year, a federally appointed Joint Review Panel is expected to launch an environmental and socio-economic review of the application for twin pipelines between Bruderheim, Alta., and Kitimat, B.C., along with a new marine terminal at Kitimat.

A 36-inch pipeline would transport 525,000 barrels per day of crude from Alberta to Kitimat, where it would be loaded onto very large crude carriers and other types of large tankers for shipment to Asian markets. The second 20-inch line would ship 193,000 barrels per day of imported condensate back to Bruderheim, where it would be used to dilute growing volumes of bitumen.

The panel, which is expected to take 18–24 months to complete its review, has not yet issued a hearing order that will formally launch the process. Initially, it is holding public meetings seeking comments on a draft list of issues, additional information that Northern Gateway should be required to file and location(s) for the oral public hearing.

The company has been conducting stakeholder and public communications and outreach for the past two years with people deployed up and down the 1,172-kilometre corridor, and that will continue, says Roth.

It is now looking forward to the public regulatory review process that will “drive a fair amount of information exchange,” he says. “Essentially, the expectation is that the regulatory review process in itself will allow more people to have their concerns addressed and their questions answered.”

The application itself is about 10,000 pages with another 11,000 pages of technical and scientific information, including third-party reports on everything from marine transportation and safety to marine mammal safety to terrestrial and environmental protection and pipeline safety. In its application, Northern Gateway says that design and operational issues include a “rigorous, multi-disciplinary route selection process designed to identify a corridor that will achieve an acceptable

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balance of engineering, environmental and economic considerations, and which will conform with land use and protected area plans in Alberta and British Columbia.”

Some of strongest opposition has come from the Coastal First Nations, a group of nine First Nations that do not have land treaties with the Canadian government and that are fiercely protective of their lands. They are part of a group of 150 First

or marine accident as massive tankers arriving from or departing to Asian ports navigate their passage past Haida Gwaii through Dixon Entrance and continue through Hecate Strait.

The Haida Nation, which claims responsibility for the waters surrounding Haida Gwaii (formerly the Queen Charlotte Islands) off the west coast of British Columbia, will certainly not accept

"It’s a new risk to our area, but at the same time the economic spinoffs are so overwhelming...and it can be done right."

— Colin Kinsley, Chair, Northern Gateway Alliance

Nations, businesses and environmental groups that are vowing to stop the project.

“Overcoming that opposition, I think, is going to be extremely difficult,” says Bob Dunbar, president of Strategy West Inc., a Calgary-based oilsands consulting firm.

The First Nations have expressed concern about the potential for an environmental disaster from a pipeline failure

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tanker traffic where it would bear the burden of risk and oil spills in its waters, according to Robert Davis, a representative of the Council of the Haida Nation.

“Our livelihoods would be jeopardized.

Many of our neighbour nations are equally concerned about impacts on their lands and water. We are willing to stand united to protect our waters.”

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Farther inland, the pipeline will cross the traditional lands of other First Nations, such as the Kitselas in the Terrace area of British Columbia, who, in a letter to the joint panel, pointed out about 110 kilometres of pipeline will cross their traditional lands, which consist of remote wildlife habitats, salmon-spawning rivers and complex geology.

Among non-governmental groups, the Pembina Institute is opposed to the proposed pipeline for a number of reasons, including the effect of construction and operations on salmon and their habitat. The pipelines would cross and in some places run parallel to major salmon rivers in the Skeena, Kitimat and Upper Fraser watersheds, which contain some of the highest quality habitat for wild salmon and steelhead trout in Canada, it points out.

“These pipelines are a clear threat to salmon in northwest British Columbia,” according to Karen Campbell, Pembina staff counsel and director. “Oil from a pipeline spill could enter salmon-bearing waters, where it would linger in riverbeds, logjams and shorelines, releasing toxins for years.”

Another major concern for Pembina is that it will drive further expansions in oilsands production before existing environ-

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OCTOBER 2010 • OIL & GAS INQUIRER

mental issues such as water use and tailings ponds have been adequately addressed.

However, the Gateway Alliance believes that those challenges can be overcome and that the economic stimulus that the project offers is critical to the region, says Colin Kinsley, chair of the group and a former mayor of Prince George, B.C. “Our group wants to see the opportunity for small business creation and expansion, job creation, training opportunities and revenue for municipalities and local governments.”

The alliance, he says, wants to ensure the public hearing brings out all the mitigation, the science, the monitoring and everything else that will ensure the project will be safe. “It’s a new risk to our area, but at the same time the economic spinoffs are so overwhelming,” says Kinsley.

From the alliance’s perspective, Northern Gateway could make the coast even safer if the super tugs that will be escorting the tankers are available for other responses and with the addition of new spill response stations that currently exist only at Kitimat. “There are just a whole bunch of positives if you look at it in that light, and it can be done right.”

Both Kinsley and Dunbar agree on the need for Canadian producers to have

another outlet for their oil, other than the United States. “The people of this area were devastated by the softwood lumber dispute when faced with countervailing duties [by the U.S. government],” says the Gateway Alliance chair. “It’s the same with oil. We have only one trading partner, but we are held captive to that one market.”

While Dunbar is fairly confident that some of the current opposition by U.S. politicians and environmental groups to what they have dubbed “dirty oil” can be overcome, “there is some uncertainty and some risk being completely dependent on that one market,” he says. Another market for Canadian crude is also important from a pure economic standpoint, according to Dunbar. “We always will be price takers in global markets, but we end up more vulnerable if we are only in single market,” he said.

A study for Northern Gateway by Houston-based consultant Muse Stancil estimated that 10 years after project startup (planned for the fourth quarter of 2016), sweet synthetic prices will rise, on average, by an additional $2.04 per barrel if the project were to proceed while Athabasca diluted bitumen prices would increase, on average, by $3 per barrel. The net benefit to the Canadian energy industry would be $28

billion over the first 10 years of the project’s operations when adjusted for transportation tolls on Northern Gateway, and after taking into account increased unit transportation costs on the Enbridge mainline system, as well as increased Canadian refinery feedstock costs resulting from the project.

The Muse Stancil study also estimated that the most likely Asian markets — China, Japan, South Korea and Taiwan — offer an opportunity for approximately 1.75 million barrels per day of Canadian-sourced crude.

In 2008, these countries imported 1.76 million barrels per day of crude, mainly from Middle Eastern countries through constricted shipping routes, which are longer than the routes from Kitimat.

As for the First Nation opposition, “we have to show them there is something in there for them,” says Kinsley. “There are lots of native bands in favour, and the ones around here are among them,” he says, citing young aboriginal people who have told him they need jobs and training.

Others see economic opportunities. “You can’t just stop everything because of fear, but that doesn’t give us a free licence. We’ve got to go in and meet with these leaders and show them it can be done safety and can be done properly.”

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Tunnel vision Northern Gateway’s engineering calls for two massive tunnels

by Elsie Ross

Shown is the electric motor of a boring machine, capable of tunnelling for miles through solid rock.

T

he proposed Northern Gateway oil pipeline, spanning 1,172 kilometres between Alberta and the West Coast, would require two major tunnels through the Coast Mountains.

Project sponsor Enbidge Inc. says the tunnels would be located about 50 kilometres northeast of Kitimat, B.C., between the Clore River valley on the east side of North Hope Peak and the Hoult Creek valley on the west side of Mount Nimbus. The Clore tunnel would be approximately 6.5 metres long, while the Hoult tunnel would be about 6.6 kilometres.

Both tunnels would be constructed using either boring machines, drilling and blasting methods, or a combination of both. Their dimensions would be the 26

OCTOBER 2010 • OIL & GAS INQUIRER

size of a small roadway: approximately 5.5 metres wide and 5.5 metres high, providing space for the pipelines, ventilation ducts and utility lines, and construction and operations equipment. Tunnelling would reduce right-of-way disturbances in the upper reaches of the Clore River and Hoult Creek valleys.

The twin pipelines (crude oil and condensate) would cross approximately 773 identified watercourses with defined bed and banks. Of those, 669 are fish bearing.

Eighty-three watercourse crossings would be subject to a detailed site review based on potential for issues and constraints.

Open cut and isolation crossing methods would be used for most of the watercourses. However, Northern Gateway is

proposing trenchless construction for 33 crossings based on known sensitivity and site-specific information.

Valves would be installed at strategic locations along the oil and condensate pipelines, including at pump stations, major watercourse crossings and other locations. A combination of wide-area network, telephone lines, satellite and radio communication would provide main and backup (where required) communication systems for remote operation of the valves.

Preliminary plans provide for the pipelines to be constructed using 12 spreads, ranging in length from approximately 74 kilometres to 192 kilometres over a 42-month construction schedule.

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an in-service date in the fourth quarter of 2016, although an additional six months might be needed to complete construction of a limited number of tanks at the Kitimat terminal.

Three spreads would be constructed concurrently during each of four construction seasons: the summer and winter of the first pipeline construction year and the summer and winter of the second pipeline construction year, although these plans likely would change after detailed engineering, says the company.

Clearing activities for the first construction season would begin the year before pipeline construction.

The Kitimat Terminal on the west side of Kitimat Arm in Douglas Channel comprises both land- and marine-based facilities. The tank terminal would include 11 oil tanks and three condensate tanks, each with a capacity of 496,000 barrels,

During operations, Northern Gateway expects that between 190 and 250 oil and condensate tankers, all double-hulled, would visit the terminal each year. while the marine terminal is comprised of two tanker berths and one utility berth.

Both tanker berths would be equipped for loading oil tankers and unloading condensate tankers. The utility berth would have facilities that can accommodate the mooring of harbour tugs and two utility workboats.

During operations, Northern Gateway expects that between 190 and 250 oil and condensate tankers, all double-hulled, would visit the terminal each year. On average, this would comprise 50 very large crude carriers (VLCCs), 120 Suezmax and 50 Aframax tankers. The average cargo capacity of these tankers ranges from 80,000 tonnes deadweight for an Aframax tanker, 200,000 tonnes for a Suezmax and 320,000 tonnes for a VLCC. Project-related vessel traffic would be controlled and monitored within the

Territorial Sea of Canada, an area that is generally referred to as the open-water area (OWA). It includes the northern and southern approaches to and from the Kitimat Terminal and encompasses Hecate Strait, Dixon Entrance, Browning Entrance, Otter Passage, Queen Charlotte Sound and other coastal waters around Haida Gwaii to the 12–nautical mile limit on the western side of these islands.

The Full Mission Bridge Simulator shows that tankers of the largest design size are capable of navigating the entire route unassisted, says Northern Gateway.

During vessel transits of the confined channel assessment area (CCA A) and OWA, a close escort tug would be used for all laden and ballasted tankers beginning at the pilot boarding stations to and from the marine terminal.

In the CCAA, a tethered tug, in addition to a close escort tug, would be used for all laden tankers. The tug would be tethered to the stern of the laden tanker at all times, ready to assist with steering or slowing down.

The close escort tug would normally be positioned approximately 500 metres from the tanker, or as directed by the shipmaster or pilot during the transit. Local pilots would board and assist all incoming and outgoing tankers. During transit of the CCAA, average tanker speeds would range between 8 to 12 knots.

A supervisory control and data acquisition system would be installed to enable the pipelines and facilities to be remotely controlled and monitored simultaneously from both control centres, in Edmonton and Kitimat. The Edmonton control centre would be used to control and remotely monitor the pipelines, pump stations, valve sites and the tank terminal. It would also be used to remotely monitor the tanker loading and unloading operations performed by the Kitimat terminal control centre.

The Kitimat control centre would be used to control and monitor the tanker loading and unloading operations at the marine terminal, and to monitor the tank terminal operations performed by the Edmonton centre.

The project would be designed with emergency shutdown systems that can be initiated remotely or locally if an unsafe condition is detected. Twenty-four hour, on-shift support for material balance system alarms and troubleshooting would be provided at the Edmonton control centre.

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OCTOBER 2010 • OIL & GAS INQUIRER

British Columbia

Mitsubishi cuts $850M deal with Penn West for B.C. joint venture

Photo: Apache Corporation

by Pat Roche

A shale gas resource estimated at 5 to 8 tcf drew Mitsubishi to Penn West’s Cordova Embayment play.

Japan’s giant Mitsubishi Corporation has agreed to spend $850 million under a joint venture with Penn West Energy Trust to develop shale gas and conventional natural gas in northeastern British Columbia.

Mitsubishi said it expects to invest 300 billion Japanese yen — roughly C$3.8 billion — in the area over the next 15 years. Penn West will serve as operator.

The 50/50 joint venture includes Penn West’s shale gas assets in the Cordova Embayment area and conventional gas assets in the Wildboy area of northeastern British Columbia. Mitsubishi will pay Penn West about $250 million for the assets at closing, and will fund about $600 million of the first $800 million of exploration and development spending in the joint venture. Penn West will pony up the remaining $200 million.

Mitsubishi said the shale gas resource in this project is an estimated five trillion to

eight trillion cubic feet. Its goal is to increase production from the assets covered by the joint venture to 500 million cubic feet per day (50 per cent Mitsubishi) from the current level of 30 million cubic feet per day.

Penn West’s Wildboy assets include 550,000 gross acres of land (including about 120,000 acres targeting shale gas in the Cordova Embayment), the Wildboy gas plant (with processing capacity for 125 million cubic feet per day) and a sales gas pipeline connecting the area to the TransCanada gathering system in Alberta.

The pipeline’s capacity can be expanded inexpensively with additional compression.

The deal is expected to close around Sept. 23 pending approval by Mitsubishi’s board of directors and Canadian federal regulators. In an unrelated development, Chinese sovereign wealth fund China Investment Corporation agreed in May to spend $817 million on Penn West’s

bitumen properties in the Peace River region of northwestern Alberta through a joint venture.

E a r l i e r t h i s y e a r, K o r e a G a s Corporation agreed to invest US$1.1 billion to develop Montney and Horn River gas assets in northeastern British Columbia under a 50 per cent joint venture with Encana Corporation. And early this summer, Encana and China National Petroleum Corporation agreed to start talks that could result in a potential joint venture, including the development of unconventional gas on Encana lands in northeastern British Columbia.

So far, Penn West has drilled five wells in the Cordova Embayment — more than any other operator, said Jason Fleury, the trust’s manager of investor relations. One of those wells has been on stream since March 2009, the other since March of this year. The two wells have combined production of between four million and five million cubic feet per day.

The overall infrastructure situation is much better than was the case when the neighbouring Horn River shale play began. Jake Jacobs, a spokesman for British Columbia’s Ministry of Energy, Mines and Petroleum Resources, said Spectra Energy Midstream has gathering systems and processing facilities in the Peggo, Tooga, and Midwinter areas in and around the Cordova Embayment.

Jacobs said potential exists in the Devonian Muskwa/Evie strata, and original gas in place is estimated at 200 trillion cubic feet. Four experimental schemes were approved in 2008 and 2009, all in the Helmet area — including two operated by Nexen Inc., one by Penn West and one by Canadian Natural Resources Limited. Cordova Embayment experimental schemes now underway are operated

by Nexen and Penn West.

— DAILY OIL BULLETIN

BRITISH COLUMBIA WELL ACTIVITY

AUG/09

AUG/10

WELL LICENCES

37

47

▲

AUG/09

AUG/10

WELLS SPUDDED

21

46

▲

AUG/09

AUG/10

WELLS DRILLED

34

43

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • OCTOBER 2010

31

British Columbia

ARC defers some Dawson wells, planning fourth gas plant With its Dawson wells performing better than expected and substantial volumes behind pipe waiting for infrastructure expansion, ARC Energy Trust has deferred plans to drill 10 Dawson wells in the second half of this year and has started preliminary planning on a fourth gas plant for the region.

T he trust ’s production averaged 66,208 barrels of oil equivalent per day for the three months ended June 30, 2010, slightly below first-quarter numbers but ahead of the 63,969 barrels of oil equivalent per day produced in the second quarter of last year. The majority of the increase in production versus last year was a result of an acquisition that closed late in 2009 with the remainder attributed to increased production in the greater Dawson area.

ARC’s new Dawson gas plant commenced operations during the second quarter, with the first shipment of sales gas occurring early in May. A number of start-up issues were addressed during the months of May and June, with the plant

operating at approximately 65 per cent of its capacity of 60 million cubic feet per day during that time period. The plant is now running at full capacity.

Assuming that its $680-million acquisition of Storm Exploration Inc. closes on schedule, ARC expects full-year average production to be between 72,500 and 74,500 barrels of oil equivalent per day.

Capital expenditures for the second quarter totalled $144 million. Year-todate, capital expenditures are $272 million. ARC has reduced its capital expenditure guidance for the full year by $15 million to $625 million. The reduction in capital is a result of better-thanexpected production capability from new wells drilled at Dawson.

Production from the greater Dawson area increased throughout the quarter with peak daily production of 100 million cubic feet per day being achieved following the commissioning of the Dawson gas plant. Average production will increase during the third quarter as production from the plant is now at the

design capacity and facility maintenance in the area is completed.

During the second quarter of 2010, ARC spent $71.1 million on development activities in the Dawson area, including drilling 11 horizontal wells and completing 14 horizontal wells. ARC incurred $9.2 million in capital expenditures on the construction of its Dawson Phase 1 gas plant during the second quarter and anticipates total costs for the Phase 1 gas plant, including associated pipeline infrastructure and an acid gas disposal well, to be approximately $70 million. To date, ARC has drilled 21 wells of its planned 32-well 2010 drilling program at Dawson.

Average production capabilities for the wells have exceeded expectations, resulting in approximately 100 million cubic feet per day of surplus capacity already behind pipe and waiting on facility capacity. The drilling of the 11 remaining wells budgeted for 2010 at Dawson will be deferred until 2011. This will result in a $45-million reduction in the capital budget for Dawson in 2010 with the funds

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British Columbia being redeployed into land acquisition and oil directed drilling activities elsewhere in the trust’s portfolio.

In April, ARC submitted an application for the Phase 2 portion of the Dawson gas plant to the BC Oil and Gas Commission (OGC). Phase 2 consists of the construction of a second 60-millioncubic-feet-per-day train at the Dawson gas plant and, if approved, is anticipated to increase the plant processing capacity from 60 million cubic feet per day to 120 million cubic feet per day at a cost of approximately $50 million.

Preliminary feedback from the OGC has been positive to date. Construction of Phase 2 is expected to be completed in

the first quarter of 2011, with the commissioning and start-up occurring in the second quarter.

Engineering design work on the Sunrise plant is proceeding on schedule.

The required public consultation process was initiated in April, with the expectation that ARC will submit its plans to the OGC in the third quarter of 2010. Completion of the gas plant is planned for the first quarter of 2012. ARC has also begun preliminary planning for a fourth gas plant for the greater Dawson area to be on stream in 2013.

Over the past four months, ARC has acquired 80 net sections of land (21,000 hectares) in township 83-85 W6 northwest

of Dawson. This increases ARC’s undeveloped land base in the main Montney fairway to 214 gross sections (198 net) and will increase further to 278 gross sections (245 net) when the Storm acquisition closes.

During the second quarter, ARC drilled one well on its Ante Creek Montney play.

Together with the completion of the debottlenecking of ARC’s oil treatment facilities and the expansion of a third-party gas plant, these activities have seen production increase to 6,700 barrels of oil equivalent per day during the quarter with peak daily production of 8,200 barrels of oil equivalent per day. Approximately 45 per cent of the production consists of liquids.

— DAILY OIL BULLETIN

Two drilling licences northwest of Fort Nelson drive British Columbia’s August land sale Two drilling licences in the Kiwigana River area northwest of Fort Nelson combined for over $64 million at British Columbia’s August land sale. The $98.15-million auction saw 31,052 hectares (ha) sold at an average price of $3,160/ha. The August 2009 sale produced just over $37 million ($1,759/ha) on 21,080 ha.

Year-to-date, $760.61 million ($2,430/ ha) has flowed into B.C. government coffers for 312,882 ha compared to $321.87 million ($1,329/ha) on 242,067 ha over the same stretch last year. “This sale, like others this year, is larger than predicted and is more evidence of the confidence the international investment community has in British Columbia’s natural gas and petroleum resources,” Energy Minister Bill Bennett said in a news release.

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70 kilometres northwest of Fort Nelson that combined for $64.85 million. Both were acquired by broker Standard Land Company Inc. That region generated the land sale high of $33.64 million.

Standard paid an average of $5,779 for a 5,820 ha parcel, which included blocks J and K at 94-O-3 and blocks B, C and G at 94-O-6. The broker also produced the per-hectare high of $9,859, acquiring a 3,166 ha parcel for $31.21 million.

The parcel included blocks G, H, I and J at 94-O-6.

Daily Oil Bulletin records show Encana Corporation licensed an exploratory horizontal well in the Kiwigana area at surface location C-15-D-94-O-7 on Aug. 3 with the Evie listed as the total depth zone with a planned depth of 5,200 metres.

Progress Energy Ltd. acquired 22 lease parcels bidding under its own name

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for a combined $16.25 million in the Blueberry area. The company’s spending included a successful $1.46-million bid for a 284 ha parcel, which included several units at D-94-A-13. Progress is a busy operator in the area, which has been heavily drilled by industry.

The sale further bolsters the company’s land position in its already extensive B.C. foothills operating area, which is expected to provide long-term growth.

“When you look at our land position there, it really is just a further bolt onto the areas where we have vertical or horizontal drilling done,” said Greg Kist, VP of investor relations. “It’s just a follow-up to our continued growth in our Montney position in that area. It certainly is more competitive there. The land position we’ve built over the years is second to none.”

— DAILY OIL BULLETIN

Read what our editor has to say. www.oilandgasinquirer.com/blog/

OIL & GAS INQUIRER • OCTOBER 2010

33

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Northwestern Alberta/Foothills

Peyto plans to drill 25 to 30 Deep Basin horizontals by year’s end

Photo: Peyto Energy Trust

by Pat Roche

Peyto expects to keep five rigs working over the second half of 2010, spending more than $70 million.

Peyto Energy Trust plans to drill 25 to 30 horizontal wells in the second half of the year as it continues to develop Deep Basin tight natural gas in the Cardium, Notikewin and Wilrich formations. The trust previously produced from these formations with vertical wells, but is now applying horizontal technology.

Since Peyto began developing its Deep Basin tight gas reservoirs with horizontal multi-stage fracture technology last fall, 21 such wells have been drilled, completed and put on production (18.3 net to Peyto). Of these horizontal gas wells, 8 are producing from the Cardium formation, 5 from the “very prolific” Notikewin and 8 from the Spirit River, said Scott Robinson, Peyto’s COO. Of the latter eight, most were drilled into the Wilrich zone within the Spirit River formation and one into the Falher member of the Spirit River, Robinson told

a recent earnings conference call. Initial test rates from the horizontal wells have varied from a low of 500,000 cubic feet per day to a high of 16 million cubic feet equivalent per day.

Of the 21 new wells, 16 have been on production for greater than one month with average first-month controlled rates of 3.7 million cubic feet equivalent per day. This average rate is about five times more than the vertical well equivalent, while the average capital required is only 2.5 times, Peyto said. This vertical well production multiple, although exciting, is expected to diminish over the life of the horizontals, according to the company.

“As we look to the balance of the year we expect to drill 25 or 30 horizontals, largely in the same formations. We also intend to test the Cadomin zone, which is another of our historically vertically

developed zones,” Robinson said. By the end of the second quarter, the 2010 drilling program was responsible for about 30 million cubic feet equivalent per day, or 23 per cent of the trust’s total production.

Operating costs were cut by 12 per cent to 38 cents per thousand cubic feet equivalent while transportation costs rose by 18 per cent to 13 cents per thousand cubic feet equivalent from the second quarter of 2009. Operating costs per unit were lower as increased production improved overall facility utilization, and warmer temperatures reduced methanol consumption.

Peyto is expanding its processing capacity to accommodate production growth during the next two quarters from its five-rig program. Robinson said three key facility projects now underway will provide an additional 40 million cubic feet per day of takeaway capacity. These three projects are to be completed over the next couple of months: • A n expansion of the Nosehill gas plant to add a second refrigeration train is to be completed mid-September. It will increase the processing capacity to 50 million cubic feet per day from 30 million cubic feet per day. Additional compression is expected to be added before year’s end to further boost the capacity to 60 million cubic feet per day.

• A large gas-gathering expansion will link one of Peyto’s key growth areas to its Wildhay plant, where the trust has about 10 million cubic feet per day of capacity available. Robinson said this project is a few weeks away from completion.

• Compressor modifications at the trust’s Oldman plant will ultimately add another 10 million cubic feet per day of processing capacity.

Peyto’s other four operated gas plants as all have sufficient excess capacity to handle the growing production volumes.

— DAILY OIL BULLETIN

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

AUG/09

AUG/10

WELL LICENCES

123

236

▲

AUG/09

AUG/10

WELLS SPUDDED

93

175

▲

AUG/09

AUG/10

WELLS DRILLED

98

146

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • OCTOBER 2010

35

Northwestern Alberta/Foothills

Parcels in the northern region and Deep Basin drive Alberta sale A lease parcel in the Deep Basin and 19 licences in the province’s northern region produced over half of the total bonus of $87.8 million at Alberta’s land sale on Aug. 4. The government sold 234,366 hectares (ha) at an average of $374.64/ha and yearto-date has generated $1.48 billion on 1.97 million hectares for an average of $753.25/ ha. To the same point last year, $151.16 million had rolled into government coffers for 932,315 ha at an average of $162.13/ha.

The Aug. 4 sale featured 19-licence parcels between 105-6 W5 and 108-5 W5 combining for a total bonus of over $35 million, all acquired by brokers. Scott Land & Lease Ltd. tendered the bonus high in the area, acquiring two separate 8,192 ha parcels at a combined bonus of

$6.59 million. The parcels included several sections at 107-3 W5, 108-3 W5, 107-4 W5, 108-4 W5, 107-5 W5 and 108-5 W5.

Daily Oil Bulletin records show that Apache Canada Ltd. rig released a vertical oil well to a total depth of 831 metres in March in the Mikkwa area at surface location 1-28-107-5 W5 with the Chinchaga formation listed as the terminating zone.

In the Deep Basin, LandSolutions Inc. tendered the bonus high of $10.88 million for a 512 ha parcel at sections 12 and 13 at 47-12 W5. The lease also produced the per-hectare high of $21,265. The parcel included petroleum and natural gas below the base of the Edmonton group, to the base of the Viking formation. Daily Oil Bulletin records show that on July

16, Daylight Energy Ltd. was issued two licences for oil objectives in the Brazeau River area at bottom locations 16-1-47-12 W5 and 13-2-47-12 W5, with the Cardium sand listed as the projected zone.

The province also generated $515,213 in oilsands bonus revenue at the auction for 1,536 ha. Paramount Resources Ltd. paid $358,245 for a 1,280 ha parcel in the Athabasca oilsands area at 81-24 W4, while Standard Land Company Inc. plunked down $156,966 for a 256 ha parcel in the Cold Lake oilsands area at 56-1 W4. Year-to-date, Alberta has brought in $9.27 million in oilsands bonus bids for 18,176 ha compared to $4.74 million on 51,593 ha to the same point in 2009.

— DAILY OIL BULLETIN

Bonnett’s revenues rise in Q2, but profits remain elusive Bonnett’s Energy Services Trust generated revenues from operations of $9.1 million for the quarter ended June 30, 2010, $2.8 million more than generated in the comparable period of 2009, but the trust still had a net loss and negative cash flow for the period.

Second-quarter revenues increased 44 per cent over the same period of the prior year as a result of increased demand for core service offerings, the trust said.

Pricing continues to remain at historic low levels; however, industry consolidation and projected increases in demand may result in price increases later in 2010, it added.

Drilling activity is a key indicator of demand for the trust’s services, and is forecast by the Petroleum Services Association of Canada to be 35 per cent higher in 2010 than 2009, which may bring added revenue to the trust, Bonnett’s said.

The trust recorded a net loss of $5.85 million for the three months ended June 30, 2010, compared to a loss of $6.32 million a year earlier. Cash flow was negative for the quarter at $1.81 million compared to negative $3.91 million a year earlier. For the six months ended June 30, 2010, revenues were up 18 per cent over the same period of the prior year, and the expectation is that this

trend will continue, the trust said. The trust’s first-half net loss was $2.88 million and it had positive cash flow of $3.59 million.

Key to continued success will be the ability to increase prices for services offered by the trust to levels that provide for the replacement of capital equipment and debt service requirements, Bonnett’s said. The trust’s debt levels remain higher than can be serviced with operating cash f lows currently being generated. The trust’s banking syndicate is working with management by providing flexible debt repayment terms until cash flows improve.

— DAILY OIL BULLETIN

Trilogy plans to expand Presley production to 150 MMcf/d Trilogy Energy Corp. has drilled 20 horizontal Montney wells in the Presley area of northwestern Alberta and is developing a plan to exploit the tight gas pools over the next 10 to 15 years, which would require increasing natural gas production to as much as 150 million cubic feet per day (MMcf/d) in this area. The company holds 50 net sections of land in the Presley area and given an estimate of 10 billion to 15 billion cubic feet of gas per section, Trilogy estimates that there may be in excess of 500 billion cubic feet of gas in place on its lands in the Montney formation.

36

OCTOBER 2010 • OIL & GAS INQUIRER

To date, well results have been better than forecast and Trilogy said it is anticipating reser ve book ings of approximately three billion cubic feet of natural gas per well plus 30 barrels per MMcf/d nat u ra l gas l iquids. I f recoverable reserves exceed this estimate, Trilogy would reduce the number of wells per section to exploit the reserves, resulting in reduced capital spending and better economics for the project.

Based on the nature of the pool and the low risk development opportunities associated with infill drilling, the company

said that each horizontal Montney well could add 600,000 barrel of oil equivalent of reserves. Assuming capital costs of $4 million to drill, complete and tie in each well, the unrisked cost of finding and development per well is a very attractive $6.67 per barrel of oil equivalent.

Sales volumes for the second quarter of 2010 averaged 24,087 barrels of oil equivalent per day, up from 23,079 barrels of oil equivalent per day for the previous quarter, and significantly above the 19,734 barrels of oil equivalent per day produced in the second quarter of last year.

Northwestern Alberta/Foothills This significant increase in production volumes over the past year was a result of the success of Trilogy’s Montney horizontal drilling program in the Presley area. Utilization of multi-well drilling pads and existing infrastructure for these horizontal wells has enabled Trilogy to condense the period between spud date and the time the wells are placed on production, thereby increasing quarterly production additions.

Trilogy’s capital expenditures (excluding acquisitions and dispositions) totalled $23.9 million for the second quarter of 2010 (of which $6 million was related to Trilogy’s Presley pipeline and Kaybob North sour gas plant expansion projects) versus $52.3 million in the prior quarter. ($4.6 million therein was related to the same projects.)

During the quarter, Trilogy participated in the drilling of 3 (0.3 net) wells; 2 wells were cased for gas and 1 for oil production. Trilogy has a royalty interest in two wells and participated for 30 per cent interest in a horizontal Cardium gas well in the Kaybob area. Drilling and completion operations on 12 wells that were spud in June will be reported in the thirdquarter report, when the wells are rig released and the results are known.

During the third and fourth quarters of the year, Trilogy will further evaluate the Montney, Bluesky, Cardium, Spirit River, Wilrich and Duvernay formations in the Kaybob area for development potential using horizontal wells.

Trilogy has entered into a joint venture with two industry partners to drill a deep horizontal well targeting the Duvernay formation; each partner has a 33.3 per cent working interest in the well. The horizontal gas well spud on June 25 has a target depth of approximately 5,000 metres measured depth and a cost of approximately $6 million to drill and complete the well. The Duvernay formation is the basinal equivalent to the Lower Leduc reefs in central Alberta and is believed to be stratigraphically equivalent to the Muskwa shale that is being exploited in northeastern British Columbia using horizontal drilling and completion technology for optimal reserve recovery.

Given success, the partnership will continue to develop the 27-section joint-venture block. In total, Trilogy has more than 100 (over 80 net) sections of land with Duvernay mineral rights in this area. Trilogy believes these assets could provide significant upside if this well and play type prove to be an

economic success, particularly in light of the Alberta government’s reduced royalty rates for shale gas wells (five per cent for three years with no volume limit).

In the first quarter of 2010, Trilogy drilled 7 (6.5 net) horizontal wells in the Presley area, 6 targeting the Montney formation and 1 into the Bluesky formation.

No wells were drilled in this area during the second quarter. However, completion operations on two first-quarter wells were finished following breakup and the access road was constructed.

Drilling and completion operations during the first half of the year have further supported Trilogy’s estimates of the ultimate reservoir development opportunity available on the company’s land base.

Well results have exceeded preliminary expectations, providing Trilogy with the confidence to move ahead with the budgeted second half of the 2010 capital program. These plans include the drilling of six (four net) horizontal Montney wells into the Presley Montney pools.

Trilogy received regulatory approval on May 6 to build and operate an acid gas disposal system to be located at the Kaybob North sour gas plant site.

— DAILY OIL BULLETIN

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OCTOBER 2010 • OIL & GAS INQUIRER

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Northeastern Alberta

Oilsands spending flattens in 2010, but planning accelerates

by Lynda Harrison

AUG/09

AUG/10

AUG/09

AUG/10

WELLS SPUDDED

77

68

WELLS DRILLED

66

78

Photo: Nexen Inc.

pated to begin mining operations in the second half of this year, while upgrading operations are expected to start in late 2010 or early 2011.

Offsetting that somewhat is Imperial Oil Limited’s Kearl oilsands mine, which is in its peak investment period. The company invested $1.38 billion in the project in 2009 and Imperial’s total capital spending for the first half of this year was up 73 per cent from 2009 to $1.78 billion (mainly due to the Kearl mine), so this year’s investment will be substantially higher.

Despite relatively flat oilsands spending this year, planning for future activity has increased this year, particularly for in situ projects after many project delays and cancellations in late 2008 and last year. But investment levels are still a long way from the hectic pace of in 2008, when oilsands capital spending reached about

$24 billion. Suncor Energy Inc. alone invested $7.39 billion on oilsands that year, on top of Petro-Canada’s $1.06 billion. The now-merged companies have a budget of $3.2 billion for the oilsands this year.

More project approvals are expected following the 2008 global recession, says a report by an equity research firm. The economic downturn created an inflection point for oilsands costs, which has resulted in companies re-starting previously shelved projects, and that is expected to continue, wrote the report’s author, Phil Skolnick, an analyst with Canaccord Genuity Corp.

Skolnick expects Suncor Energy to proceed with its proposed Fort Hills oilsands mine and for Canadian Natural Resources Limited (CNRL) to forge ahead with an expansion of its Horizon mine.

CNRL has a $735-million oilsands budget this year, which compares to actual spending in 2008 of $3.9 billion.

Suncor is expected to provide an update to its oilsands grow th plans in late 2010, including timing for its Firebag in situ project stages 4 through 6. The company is already bullish on its steam assisted gravity drainage (SAGD) pl a n s w h i c h a r e u n de r p i n n e d b y 250,000 barrels of growth from Firebag stages 3 through 6, said Skolnick in his 181-page report.

Clarity around the timing of Fort Hills could also be confirmed around the end of this year. Based on recent conversations Skolnick has had with Suncor, re-engineering of the Fort Hills oilsands mine should result in a more feasible project than under the previous operator, he said.

Skolnick is sensing continued cautious optimism from CNRL with respect to its mining expansion plans at Horizon and expects Phase 2/3 expansion sanction by early next year. Its exact design

Total oilsands capital spending is estimated at just under $14 billion this year, versus $24 billion in 2008.

With the first expansion of Athabasca Oil Sands Project approaching completion and the Kearl Lake project ramping up, estimated capital spending on oilsands projects this year is just under $14 billion, about the same as last year.

Royal Dutch Shell, along with its partners Chevron Corporation and Marathon Oil Corporation, is scheduled to complete the first expansion of the Athabasca Oil Sands Project by the second half of this year. The joint-venture owners’ capital expenditure on oilsands has fallen to the budgeted $3.34 billion this year from spending of $5.36 billion last year.

The 100,000-barrel-per-day expansion project includes construction of the Jackpine Mine, expansion of froth t reat ment fac i l it ies at t he Muskeg River Mine, expansion of the Scotford Upgrader and development of related infrastructure. Expansion 1 is anticiNORTHEASTERN ALBERTA WELL ACTIVITY

AUG/09

AUG/10

WELL LICENCES

37

44

▲

▼

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • OCTOBER 2010

39

Northeastern Alberta and size are yet to be determined. That means it could be smaller than 120,000 to 140,000 bar rels per day of sy nthetic crude oil and possibly exclude an upgrader, he said.

Peters & Co. Limited wrote in a recent energy update that it believes, based on its assessment of currently planned oilsands mining and in situ projects through 2015, including expansions, the resulting total capital spending estimate of about $30 billion will result in strong demand for oilsands services providers.

“There is a lot of activity right now,” said Bob Dunbar, president of Strategy West Inc., a Calgary-based consulting firm with a focus on Canada’s oilsands industry.

Some recovery started a few months ago when Suncor decided to reactivate Firebag 3, he added. According to his analysis, bitumen production using mining and in situ technologies is economically attractive at current oil prices.

C ono c oPh i l l ip s h a s s a nc t ione d Surmont’s second phase which is under construction, Cenovus Energy Inc. is proceeding with an expansion at Christina Lake with Phase 1C, and Devon Canada Corporation is proceeding with Jackfish

Phase 2, noted Dunbar. “I don’t think we’re to the point where we’ve got the frenzied growth that we saw a few years ago, but we have seen a pick up since the 2008–09 downturn.”

In the “batter’s box,” is MEG Energy Corp. with its in situ Phase 2B at Christina Lake, having completed its $700-million initial public offering, said Dunbar. Cenovus is moving forward with Christina Lake and Foster Creek, and Husky Energy Inc. has said that later this year it will decide whether to sanction its 50 per cent–owned Sunrise project, he said. He believes that Suncor will follow Firebag 3 immediately with Firebag 4.

A large number of projects have received regulatory approval but await sanctioning by their owners, Dunbar noted. By his estimation, projects with a total of 1.75 million barrels per day of production have been approved and 447,000 barrels per day of output is under construction. Another 1.45 million barrels per day of production have been announced and 1.65 million barrels per day are in the application stage.

Skolnick does not believe it is time to worry about major cost overruns, but he is

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keeping his eye on construction schedules.

He said cost overruns and delays are inevitable in the oilsands business; however, the Construction Owners Association of Alberta labour curve, dated May 2010, suggests that for projects currently under construction or about to commence construction, it is not time yet to worry about a return to hyper–cost inflation.

The demand for construction workers in 2010 through most of 2013 is not expected to be at the same levels as in 2008, but sanctioning of a large-scale project, like the Horizon Phase 2/3 expansions, could push the curve close to those levels, he said. “Just looking at Cenovus’ expansion plans alone and anticipating what other companies’ plans are, the construction schedule starts to get busy in a couple of years.”

In the next few years, Syncrude will be constructing two new mine trains at the Mildred Lake North Mine, which will replace existing mine trains. Construction is expected to take place between 2011 and 2014. Syncrude will also be relocating two mine trains within its Aurora North Mine during that period.

On the in situ side, several proposed projects, such as Connacher Oil and Gas

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Northeastern Alberta Limited’s Great Divide SAGD expansion and Cenovus FCCL Ltd.’s Narrows Lake, are moving towards fruition.

Connacher submitted an environm e nt a l i mp a c t a s s e s s m e nt ( E I A) application in May for approval to expand the productive capacity to 34,000 barrels per day of its Great Divide Expansion project. Cenovus has submitted its EIA report for the Narrows Lake project, which is expected to produce 130,000 barrels of oil per day.

It seems there is more construction occurring and that more projects are being resurrected as the year goes on, said Don Thompson, president of the Oil Sands Developers Group. The amount of production that will result from projects currently under construction totals about 607,000 barrels per day — 390,000 barrels per day on the mining side and 217,000 on the in

situ side, said Thompson. “We’re not quite back to where we were at the peak, but we’re getting awful close,” said Thompson.

The number of people housed in construction camps in the Athabasca oilsands region has hit more than 23,000, which is back up to the amount when the recession hit in 2008, he said, adding another metric used to gauge the level of activity is the length of the lineups at the Tim Hortons in Fort McMurray, Alta. “It’s right back to where it was during the peak in 2008. The town is bustling once again.”

One oil and gas analyst was less enthusiastic. “I’m not sure I’d say activity’s picking up,” said Justin Bouchard of Raymond James Ltd. However, a couple of companies have raised some money recently, he said, citing Athabasca Oil Sands and Laricina Energy Ltd. “Everyone’s talking about moving their project forward, but there’s no one

making a big commitment who’s in a position to make a big commitment,” Bouchard said.

There is also work at Nexen Inc.’s Long Lake in situ project, south of Fort McMurray, but Nexen is not starting new phases, just drilling more wells, Bouchard said. “That’s more work, but it doesn’t get back to where you were in 2008 in terms of activity levels and number of people; not even close,” said Bouchard. “We’re missing a couple of zeroes.”

Athabasca Oil Sands and Southern Pacific Resource Corp. are waiting for approvals, Suncor’s MacKay River project is on hold, there are no expansions going on at Syncrude and nothing’s happening at Horizon or Fort Hills or the other Total project, he said. “Someone would have to explain to me why things are back to 2008 levels. It doesn’t seem to compute for me.”

— DAILY OIL BULLETIN

Suncor’s Firebag in situ expansion is on schedule and on budget Firebag 3, a Suncor Energy Inc. in situ oilsands project, is largely on time, on budget and expected to have an attractive steam to oil ratio (SOR) of 2.6, as will subsequent phases. Firebag’s currently operating phases have an SOR of 3 to 3.3.

John Rogers, Suncor VP of investor relations, says in situ operators typically learn through experience.

Rick George, Suncor’s president and CEO, said Firebag 3 is set for full production of 62,000 barrels per day 24 months after first steam, expected in the second quarter of 2011. Firebag 4 engineering is “quite a long ways along,” he added, and Suncor expects to start installing assets on site this year with production slated to begin in the fourth quarter of 2012.

Suncor has said it will announce a schedule in the fourth quarter for the several projects it plans to complete. George listed among them the Fort Hills mine, expansion of the MacKay River project, Firebags 5 and 6, and Meadow Creek. A third upgrader, which would take at least three years to build, will be needed someday, he said.

“We still see [Fort Hills] as a valuable asset; it’s a very good mining lease.

There’s already capital investment put in there. It will be in that sequence of projects at some point,” he said of the project inherited from Petro-Canada in last summer’s merger.

Currently, with 50 per cent of its cash flow derived from oilsands, Suncor aims for that to rise to 65 per cent once its

divestitures are completed and to eventually get to 75 per cent, he said. This year’s capital spending plans of $5.5 billion in 2010 are unchanged. A second-quarter 2010 turnaround on Suncor’s oilsands operations cost less t han expected at about $295 million and at its peak employed 2,300 people.

The company initially said the merger between it and Petro-Canada that closed Aug. 1, 2009, would bring operating synergies of $300 million. Suncor then raised that estimate to $400 million and now expects to exceed that amount, said George, adding that a final tally will be announced in the third or fourth quarter of this year. Postmerger, Suncor reduced the size of its head office by about 1,000 employees.

— DAILY OIL BULLETIN

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Central Alberta

Horizontal rig release count soars to 224 as Cardium oil rush strengthens

by Paul Wells

Producers spent an estimated $560 million to $784 million on drilling Cardium horizontal wells over one year.

Oil-directed horizontal drilling in the Cardium tight sands of west-central Alberta shows no sign of slowing as the current surge in activity approaches its first anniversary. Daily Oil Bulletin statistics show 224 horizontal Cardium wells targeting oil were rig released between Jan. 1 and mid-August.

The equivalent figure for 2009 was 18 rig releases. Most of the 79 horizontal oil wells drilled into the Cardium last year were rig released in the final four months of the year. The estimated cost of a Cardium horizontal well falls between $2.5 million and $3.5 million. Based on the lower figure, 224 wells represent capital spending of at least $560 million. And that figure doesn’t include facilities, pipelines, land or seismic.

Not bad for a play that was on almost no one’s radar about a year ago. By comparison, 340 horizontal wells have been

drilled so far this year in the Bakken tight oil formation of southeastern Saskatchewan, where activity has been building since about 2005.

Most of the Cardium oil activity is centred on the Pembina and Garrington areas, but producers are testing the play concept across the oil trend’s vast 22,000-square-mile

western Canada with an estimated 10 billion barrels of original oil in place, including 7.8 billion barrels at Pembina.

Past production was typically from vertical wells drilled into the more permeable, large-grain conglomerate rock. The current horizontal drilling focus is mostly on the tight sands where most of Cardium’s vast oil prize resides.

As in the Bakken and gas shales, improvements in horizontal drilling and completion technology — especially the ability to do multiple fracture stimulations in a single wellbore — prompted operators to re-evaluate plays that traditionally were uneconomic.

The pace of Cardium oil drilling is expected to accelerate further once PetroBakken Energy Ltd. is able to mount a full program. The mid-sized producer, which previously focused only on the Saskatchewan Bakken, entered the Cardium in a big way early this year with the acquisition of Berens Energy Ltd., Result Energy Inc. and Rondo Petroleum Inc. PetroBakken’s plans to drill Cardium wells this year have been constrained, as wet weather prevented lease access. So far, PetroBakken has rig released only five horizontal wells in the play (excluding six drilled by Result, four by Rondo and two

by Berens) this year.

Most of the Cardium oil activity is centred on the Pembina and Garrington areas, but producers are testing the play concept across the oil trend’s vast 22,000-square-mile fairway. fairway. Emerging areas stretch from the Pine Creek/Edson region in the northwest to the Ferrier/Willesden Green area in central Alberta to the Lochend/Crossfield area near Calgary in southern Alberta.

Discovered in the 1950s, the Cardium is by far the biggest light oil deposit in

According to Daily Oil Bulletin statistics, the Cardium’s top horizontal driller under its own name this year is NAL Oil & Gas Trust with 21 oil-directed horizontal Cardium wells rig released at the end of August. NAL is credited with unlocking the Cardium’s potential with four multi-frac

AUG/09

AUG/10

AUG/09

AUG/10

WELLS SPUDDED

143

251

WELLS DRILLED

146

254

CENTRAL ALBERTA WELL ACTIVITY

AUG/09

AUG/10

WELL LICENCES

89

273

▲

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • OCTOBER 2010

43

Central Alberta horizontal wells drilled at Garrington in the fourth quarter of 2008. In the wake of NAL’s Garrington success, other producers began drilling the outer fringe, or halo, of the Pembina Cardium last year.

If merged companies are included, the top Cardium horizontal driller is Daylight Energy Ltd. at 23 (including wells rig released this year by Daylight Resources Tr ust and West Energ y Ltd. Unless otherwise indicated, all well counts refer to year-to-date rig releases of operated horizontal wells targeting Cardium oil.)

In third place is Bonterra Energy Corp. with 15, followed by Penn West Energy Trust with 13.

Penn West has by far the biggest Cardium land position due to its acquisition of BP Amoco plc assets at Pembina in 1999. “The more results we see, the more we like where this play is headed,” said Murray Nunns, Penn West’s president and COO. Nun ns predic ts Pen n West w i l l ultimately be the lead driller on the Cardium. But for now, the trust is content to work on a few select areas, letting the industry prove up the rest of its lands. Nunns estimates that about 100 competitor wells have been drilled within a mile or two of Penn West acreage. With

13 wells already rig released, the trust has already drilled the bulk of the 15 to 20 Cardium wells it plans for 2010.

Other operators with significant horizontal Cardium well counts this year are: Bellatrix Exploration Ltd. (11), Midway Energy Ltd. (10), Spry Energy Ltd. (10), ARC Energy Trust (9) and Sifton Energy Inc. (9). Vermilion Energy Trust, Anderson Energy Ltd., Angle Energy Inc., Bonavista Energy Trust and Spartan Exploration Ltd. each drilled 7 wells, while NuVista Energy Ltd. and Vero Energy Inc. each drilled 6.

Few, if any, resource plays have such a diverse range of operators.

Exoro Energy Inc., Baccalieu Energy Inc., Korea National Oil Corporation (through its wholly owned Har vest Operations Corp.), Pengrowth Energy Trust, Seaview Energy Inc., Perpetual Energy Inc. (formerly Paramount Energy Trust) and Delphi Energy Corp. each drilled three wells.

Others include Base Resources Inc., Enterra Energy Corp. (two wells each), Baytex Energy Ltd., Tournament Exploration Ltd. and Onyx 2006 Inc. (one well each).

Senior producers who have drilled one well each include Canadian Natural Resources Limited, Husky Energy Inc., Apache Canada Ltd. and EOG Resources Canada Inc.

In a December 2009 repor t that dubbed the Cardium “Alberta’s Bakken,” Macquarie Capital Markets Canada Ltd. wrote: “There are virtually countless producers with land positions in the Cardium due to farm-ins, acquisitions or the inheritance of legacy acreage.” In an April 5 report on emerging oil plays, Macquarie correctly predicted horizontal drilling in the Cardium was “set to explode” this year.

Due to the fragmented ownership, Macquarie also expects more mergers and acquisitions in the tight oil play. However, the investment firm doesn’t expect the patchwork ownership to impede development because there are enough players with significant holdings. Besides Penn West and ARC, producers with meaningful stakes in the vast Cardium oil trend include Bonavista, NAL, Daylight, Pet roBa k ken, Ver m i lion, Bonter ra, Talisman Energy Inc., Enerplus Resources Fund and ConocoPhillips Company.

The prize is huge. “You’re almost looking at twice as much oil in place at Pembina than you are in the Bakken at Viewfield,” said Macquarie analyst Cristina Lopez, co-author of the December and April reports.

— DAILY OIL BULLETIN

Liquids pipeline will strengthen use of off-gas for petrochemicals With little fanfare, Williams Energy (Canada) Inc. is going ahead with a $340 -million high–vapour pressure liquids pipeline that will tap oilsands off-gas as a petrochemical feedstock.

Alberta Energy Minister Ron Liepert said the Williams investment will drive “a huge secondary industry in the province” that had not previously been identified by oilsands producers.

Over time, Williams would like to expand its capital commitment to about $1.5 billion, investing in the proposed pipeline, three off-gas extraction plants at oilsands sites, and a fractionating and distribution facility near Redwater, north of Edmonton. The off-gas can be substituted for ethane, a petrochemical feedstock that’s now in short supply. It can also be transformed into propylene and poly proylene, which are major petrochemical building blocks.

There is a proviso in this grand design, however. “For our business to work, 44

OCTOBER 2010 • OIL & GAS INQUIRER

we have to have bitumen upgraded in Alberta,” said David Chappell, Williams’ Canadian regional VP. “We’re part of the value-added chain of upgrading.”

On June 6, t he A lber ta Energ y Resources Conservation Board approved Williams’ application for the proposed pipeline. The 12-inch, 419-kilometre

distribution facility near Redwater. This plant processes 100 million cubic feet per day of Suncor off-gases into 15,000 barrels per day of liquids, including propane, propylene, condensates, butane and butylene. The Redwater plant is undergoing a $57-million upgrade that will allow it to split butane and butylene components.

“For our business to work, we have to have bitumen upgraded in Alberta. We’re part of the value-added chain of upgrading.”

— David Chappell, Regional VP, Williams Energy (Canada) Inc.

high–vapour pressure line, called Boreal, will have an initial capacity of 45,000 barrels per day, with ultimate capacity of 125,000 barrels per day.

Williams already operates a cryogenic liquids extraction unit near Fort McMurray, Alta., collecting bitumen offgases at the upgrader belonging to Suncor Energy Inc. It also has a fractionating and

The upgrade will enable production of octane, a gasoline additive.

Eventually, Williams wants to build cryogenic liquids extraction plants at the bitumen upgraders belonging to Syncrude Canada Ltd. and Canadian Natural Resources Limited (CNRL), also near Fort McMurray. Negotiations are underway with the two oilsands mining firms.

Photo: Joey Podlubny

Central Alberta

Off-gas from Shell's Scotford upgrader will be turned into hydrogen, ethane and a propane-plus mix.

“Our goal is to process all the off-gas from Suncor, Syncrude and CNRL, which right now would be 80,000 barrels per day of liquids, as well as from any expansions or other upgraders,” Chappell said.

Williams currently ships its off-gases as batches on a multiple products pipeline, but this method can negatively affect operations at the Redwater plant.

Future expansion creates the need for a dedicated pipeline, Williams said. On June 23, the company announced it had awarded the contract for construction of the Boreal pipeline to Willbros Group Inc. Construction is slated to start this fall and be completed by April 2012.

Suncor previously burned its offgases, which contain natural gas liquids and olefins, as a substitute for natural gas. CNRL and Syncrude continue to do the same. Liepert says off-gases would be far more valuable as feedstock for an

expanded petrochemical sector, especially with natural gas prices at their current low levels.

Williams plans to spend several million dollars on retrofitting the Suncor liquids unit so it can extract ethane, the main feedstock used by Alberta’s petrochemical industry. It would include similar technology at the CNRL and Syncrude upgraders. Ethane is a component in natural gas, whose production has declined in Alberta.

Nova Chemicals Cor poration announced in mid-July it had signed a deal with Hess Corp. to purchase and transport 45,000 barrels daily of ethane from that firm’s Tioga Gas Plant in North Dakota, with the ability to expand to 60,000 barrels daily. It’s the first time Nova has been forced to import ethane for its Joffre petrochemical complex near Red Deer, Alta.

Liepert believes the value-added processing of bitumen holds the key to both

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preserving and expanding the province’s petrochemical industry. “I feel strongly [that] we have a solution sitting in front of our faces,” the energy minister said.

Alberta exports propylene, a byproduct of natural gas processing and oil refining that is used to manufacture products like car components and packaging materials.

The Williams off-gas project would generate more propylene. The company is working with the Alberta government to attract a new plant, which would utilize the province’s propylene as feedstock.

There is currently no polypropylene-based plant in Canada.

Chappell says that CO2 will be reduced by one million tonnes per year and sulphur dioxide emissions by nine tonnes a day if Williams has facilities at the Suncor, Syncrude and CNRL coker upgraders. If the proposed off-gas system is built, the pipeline, three extraction plants and fractionating facility would generate about 100 permanent jobs. The budding propylene sector could create hundreds of additional jobs.

Williams isn’t the only company trapping bitumen off-gases for use in valueadded products. On July 5, Aux Sable Canada LP announced it had signed a longterm deal with Shell Canada Products to access off-gases from Shell’s Scotford upgrader, near Edmonton. Aux Sable will process 20 million cubic feet per day of off-gas and will produce hydrogen, ethane and a propane-plus mix.

The Shell off-gas will be a feedstock for Aux Sable’s Heartland Offgas Plant, located in Fort Saskatchewan, Alta. The off-gas will be delivered from a Shell pipeline located near the Aux Sable plant.

“Off-gas has the potential to be a growing source of new feedstock supply for Alberta’s petrochemical industry,” said Tim Stault, executive VP of Aux Sable.

— DAILY OIL BULLETIN

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Southern Alberta

Service companies rebound due to intense resource-play development

by Paul Wells and Richard Macedo

AUG/09

AUG/10

AUG/09

AUG/10

WELLS SPUDDED

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283

WELLS DRILLED

95

285

Photo: Trican Well Services Ltd.

Services Group Inc., Calfrac Well Services Inc. and Trican Well Services Ltd., all of which have reported stellar secondquarter results. The three firms posted combined second-quarter revenues of $494 million, double last year’s numbers and up from $261 million in the second quarter of 2008.

A decision by Canyon Services Group two years ago to transition away from a shallow gas focus to services targeting resource play development is paying off.

The company saw its second-quarter revenues surge sixfold from the same period last year to $22.8 million, thanks in large part to the rapid growth in its hydraulic pumping capacity and customers’ desire to use it. Earnings and cash flow were also up considerably.

“Strategically, we started that shift almost two years ago — it’s what we had to do. We knew the world was moving

away from the shallow gas to the deeper, more complex resource plays,” said Joe Peskunowicz, Canyon’s executive VP, corporate. “Then a year ago is when we actually started doing actual things to get us there in the sense we started working on our limited equipment spread.”

Last year, the company started adding to its hydraulic horsepower (HHP) capacity, an initiative that took it from 25,000 HHP to its current 75,500 and on its way to 125,000 HHP by year-end, a move that will position the company at the “tier-two level” of outfits offering pressure pumping in western Canada, Peskunowicz said.

In his judgment, the positive secondquarter performance of his company, as well as others with a slant towards resource-play development, is an encouraging sign that the worst of the prolonged downturn is in the rear-view mirror. “From an industry point of view, that positive trend indicates that our Canadian oil and gas industry has rebounded significantly from an activity-level point of view,” the Canyon executive said.

That said, Peskunowicz noted that there is room for upward movement on pricing, which he says has yet to rebound to levels witnessed pre-downturn. “We still haven’t even returned to 2005-level pricing. There’s going to be a balance between the economics of the plays and the pricing side of things,” he commented.

Peskunowicz is confident that the upward trend his company is currently enjoying will continue to play out the remainder of this year. “Failing a worldwide economic meltdown and $1 gas — those are things that are out of our control.

But our clients are putting forward very strong capital budgets and very active programs, and we see that the companies going after the oil are very profitable with what they are doing,” he said. “And the gas guys are going after those resource plays

Trican earned $8.7 million in this year’s second quarter, up from a loss of $25.5 million in Q2 2009.

The times they are a-changin’ in the petroleum ser vice sector — for the better. Peters & Co. Ltd. predicts that the median year-over-year increase in service companies’ second-quarter EBITDA will be in the neighbourhood of an impressive 25 per cent. And those operators with good exposure to crude and natural gas resource plays are leading the charge.

EBITDA refers to earnings before interest, taxes, depreciation and amortization. It’s an approximate measure of a company’s operating cash flow. “Based on the ongoing change in typical well profile [deep horizontal wells that are selectively fracture stimulated multiple times], we expect that pressure pumpers, directional drillers [and companies with deep drilling fleets] will report favourable second-quarter results,” Peters & Co. said in a service sector report.

Three services companies that fit the Calgary brokerage’s profile are Canyon SOUTHERN ALBERTA WELL ACTIVITY

AUG/09

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WELL LICENCES

101

213

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Source: Daily Oil Bulletin

OIL & GAS INQUIRER • OCTOBER 2010

47

Southern Alberta

to get large amounts that they can produce, and I think that as long as gas prices stay in that $4 [per thousand cubic feet] to $4.50 range, things look okay.”

Thanks to a high level of pressure pumping activity in unconventional plays in western Canada and the United States, Calfrac Well Services Ltd. had record second-quarter revenue, and the company expects this to continue. North American pressure pumping demand is anticipated to remain strong over the long term because of burgeoning unconventional natural gas and oil plays, which remain profitable at relatively low commodity prices.

Calfrac’s second-quarter numbers were buoyed by horizontal and hydraulic fracturing in its Horn River and Montney operations, and oil resource plays in the Deep Basin, Cardium and Bakken. For the three-month period, the number of fracturing jobs in Canada rose to 455 from 143 the previous year and for the six months ended June 30, fracturing jobs jumped to 1,476 from 1,008 over the same stretch a year ago.

Development of oil plays in western Canada has diversified the basin over the past year. Development of these plays employing horizontal drilling with multistage fracturing is still in its infancy, noted Douglas Ramsay, president and CEO of

Calfrac. “Our customers are just [at the] tip of the iceberg,” he said. “They’re looking at not only the Cardium [and] the Viking, but [also] a lot of other formations that could lend themselves to this horizontal — either completion or recompletion — style of business.”

T he compa ny ’s r e ve nue i s now about 30 or 40 per cent weighted to oil. Ramsay is also cognizant of labour shortages that can occur in a heated market, but he said things to this point haven’t been out of control. “We certainly haven’t seen ridiculous competition among ser vice companies to get employees,” he reported.

Trican Well Service Ltd. reported that it earned $8.7 million in the second quarter compared with a loss of $25.5 million a year ago, while revenue more than doubled. The Calgary-based oilfield services company said revenue was $306.3 million, up from $136.3 million last year.

Canadian revenue increased 198 per cent to $140 million for the quarter compared to the second quarter of 2009.

The increase in revenue was attributed to the growth in fracturing on horizontal wells, which has also led to an increase in revenue per job of seven per cent from the first quarter of 2010 and 103 per cent from the second quarter of 2009.

As expected, second-quarter results were impacted by spring breakup conditions; however, activity levels benefited from the extension of first-quarter completions work into the second quarter, increased year-over-year activity in the Montney, Cardium and Viking regions, and more pad work, which is less prone to work stoppages from road bans.

Dale Dusterhoft, Trican’s CEO, said the year-over-year increase in both rig count and completions work performed on horizontal wells in western Canada led to increased equipment utilization, which provided “opportunities for pricing improvements.” Second-quarter pricing increased by nine per cent compared to the second quarter of 2009.

With demand for fracturing capacity continuing to be on the rise and with many service companies responding by adding horsepower, the supply and demand balance for that service is shifting. But Dusterhoft believes the Canadian marketplace will be able to absorb the increase: “Based on preliminary discussions with our customers regarding 2011 industry activity levels, we are of the opinion that the Canadian market should be in the position to absorb the additional capacity, and as a result, we currently expect supply and demand to be in balance during 2011.”

— DAILY OIL BULLETIN

PSAC still expects a 35 per cent increase in the 2010 well count I n it s t h i r d- qua r te r d r i l l i ng for e cast update, the Petroleum Ser v ices A ssociat ion of Canada (PSAC), has maintained its previous forecasts of 11,250 wells to be drilled (rig released) across Canada this year, representing a 35 per cent increase in total wells drilled compared to the final tally for 2009 of 8,350 wells.

PSAC’s Drilling Activity Forecast update finds positive signs balanced by negative factors. While there is optimism that the global economy is recovering, uncertainty continues to hang in the air as negative economic indicators in the United States and abroad persist.

Oil prices continue to maintain levels sufficient to provide a reasonable rate of return on investment; however, gas prices continue to languish, making most 48

OCTOBER 2010 • OIL & GAS INQUIRER

conventional plays uneconomic, offsetting any upside gains from oil drilling activity for the remainder of this year.

PSAC is basing its updated 2010 forecast on average natural gas prices of US$4.50 per thousand cubic feet (AECO) and crude oil prices of US$78.50 per barrel (West Texas Intermediate).

“Exacerbating any potential increase in activity levels is the challenge of finding skilled labour for those companies fortunate enough to be busy,” said Roger Soucy, president of PSAC. “Companies forced to shed valuable employees last year are now scrambling to hire them back or find replacements.”

On a provincial basis for 2010, PSAC is forecasting 7,390 wells will be drilled in Alberta, a 27 per cent increase over final 2009 drilling levels. PSAC expects

that British Columbia will see 700 wells drilled, a 22 per cent increase in drilling from 2009, and Saskatchewan will see 2,670 wells drilled, a 41 per cent increase over the 1,892 wells drilled in 2009. The association expects that Manitoba will also increase its drilling activity as 450 wells are being forecasted, representing a 90 per cent increase over the 235 wells drilled in 2009.

Daily Oil Bulletin records show companies finished 4,796 wells in western and northern Canada to the end of June, up nearly 29 per cent from 3,731 wells a year earlier, but still the second-lowest well count since the year 2000. The average well depth of 1,756 metres, however, is the highest since the Daily Oil Bulletin began tracking metres drilled in 1988.

— DAILY OIL BULLETIN

Southern Alberta

Montana Bakken exploration play starts spilling into Alberta A t ight roc k oi l play t hat ’s bei ng developed i n nor t her n Monta na is piquing investment in Alberta where companies have been scooping up land along the Canada/U.S. border. In fact, interest extends as far as northern British Columbia. Drilling activity to this point, however, has been concentrated south of the border.

According to a report by Macquarie Research, the Bak ken shale on the Montana side of the Alberta basin and its geological equivalent, the Exshaw shale on the Canadian side, are the same age: late Devonian to early Mississippian, and of similar deposition to the Williston Basin Bakken shale, but are part of a separate geological system.

The targeted shale is black and organic rich and thought to be the main source rock for many oil reservoirs in the Alberta basin. The Bakken/Exshaw varies in thickness from 10 feet to over 100 feet and depth from 4,500 to 7,500 feet.

“This Exshaw/Bakken shale is regionally very extensive. We can map the shale itself from northern Montana all the way up through Alberta...northward into the Horn River Basin and into the [Northwest] Territories,” said Brad Hayes, president of Petrel Robertson Consulting Ltd. “At the other end, [Quicksilver Resources Inc.] up in the Horn River Basin...is talking about exactly the same layer looking for oil potential.”

“It’s got a very large regional extent for the particular formation,” Hayes said. “I think the question is, where are you going to find it where it’s got the right reservoir conditions? Of course, it won’t be just one massive oilfield; there will be places where it works and places where there’s different reasons it doesn’t work.”

Interest in Alberta has been revealed by recent land sales. At a sale in April, land in the Del Bonita area along the Canada/ U.S. border helped drive total bonus revenue of $55.08 million. Thirteen lease parcels between 1-20 W4 and 2-22 W4 in the extreme southern part of the province drew over $18 million.

In June, interest along the border continued. Several licences acquired in the July 21 Alberta sale northwest of Lethbridge, which fetched a combined $47.72 million in bonus bids, may have been due to interest in the Bakken/ Exshaw oil play. Several parcels have been posted along the border in the Sept. 1 Alberta land sale.

Daily Oil Bullet in records show Antelope Land Services Ltd. spudded a new field wildcat horizontal well targeting oil in the Del Bonita area on July 24 at surface location 2-7-1-21 W4 with the Wabamun group listed as the projected zone to a planned depth of 3,400 metres.

Land brokers rarely operate wells in western Canada and only when the true operators are keen to keep their identity confidential.

On July 22, Connaught Oil & Gas Ltd. was issued a licence for a horizontal oil well in the area just slightly north of the Antelope well at surface location 14-71-21 W4 with the Rundle group listed as the projected zone and a planned depth of 2,978 metres.

Calgary-based Blacksteel Energy Inc. said it has accumulated a land position at Del Bonita. According to a corporate presentation, the company has identified and mapped out a light oil resource play in the mid-30 degrees API. The multi-zone play would be exploited using horizontal drilling and multi-stage fracturing technology.

“Our belief is that it does extend into Canada,” said Jacques Soroka, Blacksteel’s president. “We’ve got four sections that we bought in April.” Blacksteel says it’s an early mover on the play and currently holds 1,024 hectares in a sweet spot of the resource play.

“We’ve got what, we believe, is one of the better tracts of land for this play, at least north of the border. We’re right on the border.”

Soroka said the company is seeking partners. “These horizontal wells are fairly capital-intensive, so being a small company, we have to be careful on how we spend our money,” he added. “We are developing our plans for the area as we speak.” The play has been mapped using well logs and core samples and has some associated horizontal production and is analogous to the development taking place in the Bakken in Montana and North Dakota.

Blacksteel’s acreage is located near Mont a n a de ve lopme nt by Roset t a Resources Inc. and Newfield Exploration Company. In Montana, Rosetta, Newfield, Quicksilver, Stone Energy Corporation and Abraxas Petroleum Corporation, among others, have established land positions. Rosetta began to establish its acreage position in Glacier County on the Blackfeet Indian reservation in 2008, according to Macquarie’s report.

“We do not have a position in Alberta, therefore, obviously we are not ourselves intending to test the play that far north,” said Ellen DeSanctis, Rosetta’s executive VP, strategy and development. “We do expect for somebody, some companies in the future, to begin drilling and testing the play on the Canadian side.”

— DAILY OIL BULLETIN

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Peak Energy Services Trust generated revenue of $27.8 million for the second quarter of 2010, which was a 32 per cent or $6.7-million increase over the same prior year period revenue of $21.1 million.

The primary drivers of the increase were increased activity levels in both the U.S. and Canadian markets. However, low prices for Peak’s services offset the greater workload.

The trust realized a net loss from continuing operations of $4.5 million, which was a decrease of 16 per cent or $900,000 from the net loss of $5.4 million for the same period in 2009. Funds from operations were a negative $1.1 million for the three months ended June 30, 2010, versus a negative $3.3 million a year earlier.

Canadian drilling operating days for the second quarter were 77 per cent higher than the prior year period, and wells drilled increased by 42 per cent to 1,197 wells. Over the first half of 2010, Canadian drilling rig operating days were 45 per cent higher than the prior year period, and wells drilled increased by 26 per cent to 4,843 wells.

Peak recognized a loss on sale of equipment of $4.1 million as a result of the current negative market conditions for selling of used equipment.

The trust expects to see the continuation of more activity in oil-focused resource plays, such as the Cardium (Alberta), Bakken (Saskatchewan and North Dakota) and the oilsands (Alberta) regions as confidence grows that oil prices will be sustainable above $75 per barrel. The number of opportunities to bid on project work within these regions is starting to increase fairly significantly, the trust noted. Peak has taken advantage of these more active oil-related areas by re-deploying assets into these oil-focused regions.

In the United States, Peak’s revenue has more than tripled in 2010 year-todate versus the same period in 2009. The majority of this growth was realized in the Marcellus shale region of Pennsylvania.

Due to further expansion efforts in other

American regions, Peak said it expects to see its U.S. operation to more than triple in size, to more than $30 million in revenue for 2010 compared to 2009. “ We a re cur rent ly ma k ing some progress with increased pricing in certain markets and expect this trend to continue during the second half of the year,” Peak said in its second-quarter report. “Management is cautiously optimistic at this time that both the global economy and the oil and natural gas industry are starting to show some signs of a recovery. We believe that, at the very least, we are on the back side of the bottom of this cycle.”

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— DAILY OIL BULLETIN

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Black Diamond has also been awarded a second phase of a previously announced contract for a major Canadian gas company commencing in February 2011. The project, located on the west side of the Horn River Basin in northeastern British Columbia, has a contract value of $4 million, with rental revenue commencing in March of 2011. This camp will consist entirely of executive, VIP-style accommodations and will feature a state-of-the-art kitchen and modern recreation facilities.

The capital expenditure for these projects is part of the company’s previously announced $99-million budget for 2010.

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Saskatchewan

Australia’s Molopo quietly builds up tight oil reserves in the West

Photo: Brian Zimchuk, Pipeline News

by Paul Wells

Producers in Manitoba’s Spearfish/Waskada play include Molopo, CNRL, Penn West and EOG Resources.

Molopo Energy Ltd. has quietly racked up reserves and acreage in Manitoba’s Spearfish and Saskatchewan’s Bakken tight oil plays, scoring well with the drill bit. GLJ Petroleum Consultants pegs the Melbourneheadquartered producer’s proved-plusprobable reserves at 9.2 million barrels.

Molopo also holds 2.2 million acres of speculative shale gas acreage in Quebec.

In August 2009, Molopo acquired two privately held Canadian companies for $27.4 million in cash and shares.

Production at the time was 90 barrels per day, with proved-plus-probable reserves of 475,000 barrels. “The dramatic reserves grow th picture emerging f rom our Canadian tight oil operations is a result of the successful 13-well drilling campaign conducted in early 2010,” says Stephen Mitchell, Molopo’s managing director.

“Molopo was one of the first Australian companies to move into the shale gas

and unconventional oil industry in North America. Our large land position across several different plays was acquired before land prices soared,” Mitchell adds.

“Molopo has one of the largest land positions in the Spearfish tight oil play.”

“Importantly for an oil resource play, substantial [proved, probable and possible] reserves have been certified at 11.1 million barrels, while a large high-case contingent resource of 21 million barrels was also granted,” the company said in the release. Molopo is publicly traded in Australia.

Its core acreage at Spearfish includes 30 gross sections within its overall gross land position of 56 sections. Original oil in place (OOIP) is estimated at 12 million barrels per section and is expected to yield a recovery of approximately 10 per cent at eight wells per section and approximately 15 per cent at 12 wells per section. Molopo’s net position within the certified core area stands above 75 per cent, yielding a net OOIP of 270 million and 27 million to 40 million barrels recoverable.

O t he r c omp a n ie s work i n g t he Spearfish (also called the Waskada field) include Canadian Natural Resources Ltd., Penn West Energy Trust and EOG Resources Inc. By June, Molopo had drilled seven horizontals and a few verticals.

“When we first purchased the Spearfish, we had perhaps 11 to 15 sections that were prospective,” Mitchell says. “But as

“Molopo was one of the first Australian companies to move into the shale gas and unconventional oil industry in North America."

— Stephen Mitchell, Managing Director, Molopo Energy Ltd.

In August, Molopo’s Canadian subsidiary announced GLJ’s assessment: proven reserves of 4.5 million barrels, proved-plus-probable reser ves of 9.2 million barrels and an additional 8.8 million barrels of best-estimate contingent resources. Most of those reserves are at t r ibuted to Spearf ish, a light oil prospect.

our drilling stepped out...we now believe at least 30 sections of land within the Spearfish are highly prospective.”

In a recent corporate presentation, Molopo reports Spearfish well cost at around $1.8 million. Average initial production rates are about 150 barrels per day, with first-year production declines estimated at around 60 per cent.

AUG/09

AUG/10

AUG/09

AUG/10

WELLS SPUDDED

172

266

WELLS DRILLED

165

277

SASKATCHEWAN WELL ACTIVITY

AUG/09

AUG/10

WELL LICENCES

149

350

▲

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • OCTOBER 2010

53

Saskatchewan “Molopo plans to further increase Spearfish reserves over the next two to three years by expanding its acreage, drilling more wells, improving initial production rates by optimizing well completions and increasing the number of wells per section to 10 to 12,” notes John Young, an analyst with Australia’s Whilst Wilson HTM Investment Group, in an Aug. 11 note. Waterflooding would be a possibility in the future.

In June, Molopo said its Canadian oil-production potential reached approximately 900 barrels per day, achieving

the mid-year oil target range of 800 to 1,000 barrels per day net. The company is targeting 2,000 barrels per day by the end of 2010 and 3,000 barrels per day by mid-2011.

Molopo holds a total of 82 gross (100 per cent working interest) sections in the Bakken play. Four horizontal wells have been drilled and completed in the Estevan area, while two horizontal wells have been drilled and one completed in the Weyburn area. “In comparison to the Spearfish, the Bakken has a lower average OOIP at approximately four million barrels per

section and is expected to be developed with a well density of four wells per section,” Molopo said in a public statement.

I n Q ueb ec , Molop o i s r a mpi ng up to drill its first well, St. Marc sur Richelieu-1, in the second half of this year. Three other Richelieu-area drilling locations have also been identified. In June, the company had 15 employees in Canada. It also has stakes in several coalbed methane sites in Australia, two South African prospects and a gas project in the United States.

— DAILY OIL BULLETIN

Enbridge announces Bakken Pipeline Expansion Program Enbridge Energy Partners L.P. (EEP) a nd Enbr idge Income Fund (E N F) are proceeding, subject to customary regulatory approvals, with a joint project to further expand crude oil pipeline capacity to accommodate growing production from the Bakken and Three Forks formations located in Montana, North Dakota, Manitoba and Saskatchewan.

The Bakken Expansion Program will increase takeaway capacity from the Bakken play by 145,000 barrels per day, which can be readily expanded to 325,000 barrels per day at a low cost. The two companies are affiliates of Enbridge Inc. “This latest in a series of expansions will provide shippers with favourable tolls, diverse market alternatives and batch

undertaken by Enbridge Energy Partners at a cost of approximately US$370 million and Canadian projects that will be undertaken by ENF at a cost of approximately $190 million.

The expansion program will originate at Beaver Lodge Station near Tioga, North Dakota, in the heart of the Bakken, and will follow existing EEP and ENF rights of way to terminate at and deliver to the Enbridge mainline terminal at Cromer, Man. In addition, EEP has proposed a separate project to expand its pipeline system south of the Missouri River, connecting to Beaver Lodge Station and providing increased access to the expanded North Dakota System. Once on the Enbridge mainline, Bakken production will have access to the

“This latest in a series of expansions will provide shippers with favourable tolls, diverse market alternatives and batch quality maintenance for this high-quality light sweet crude."

— Stephen Wuori, Executive VP, Liquids Pipelines at Enbridge Inc.

quality maintenance for this high-quality light sweet crude. Further, the Bakken and Three Forks formations represent an area of tremendous opportunity for both Enbridge Energy Partners and Enbridge Income Fund,” said Stephen Wuori, executive VP, liquids pipelines at Enbridge Inc. “We anticipate substantial further production growth based on discussions with producers, and our own regional supply analysis. We are well positioned to provide shippers with attractive transportation options based on our extensive existing operations in the region,” Wuori said.

Enbridge’s Bakken Expansion Program will involve U.S. projects that will be 54

OCTOBER 2010 • OIL & GAS INQUIRER

multiple markets accessible from the mainline and connected pipeline systems.

The program is a series of pipeline expansion projects that will provide approximately 145,000 barrels per day of incremental capacity from North Dakota into the Enbridge Mainline at Cromer, Man., by the first quarter of 2013.

EEP and ENF have received sufficient long-term shipping commitments from anchor shippers to enable the Bakken Expansion Program to proceed. A binding open season is planned to provide other shippers with the opportunity to make shipping commitments between Berthold and Cromer on the same terms as provided

to anchor shippers, as well as to provide an opportunity to commit to capacity on the proposed expansion of EEP’s pipeline system in northwestern North Dakota.

ENF’s Saskatchewan System is currently undertaking three separate expansions, expected to be in service late this year, that will collectively increase upstream capacity of the gathering systems by 125,000 barrels per day. Total capacity into Cromer following the current (Phase 2) and the previously completed Phase 1 expansion will be 230,000 barrels per day.

“We are confident that this series of expansions will relieve much of the current demand for pipeline capacity out of the Bakken and Three Forks production areas as well as provide the foundation for timely future expansions to meet the needs of the region,” Wuori said. “The suite of projects we’re proposing will provide firm access from North Dakota oilfields to the two-million-barrel-perday Enbridge Mainline System. Along with ongoing reliable service for existing shippers on EEP’s North Dakota System and ENF’s Saskatchewan System, the expanded systems optimize segregated light sweet pipeline capacity serving the Great Lakes region of the Upper Midwest and the mid-continent refinery markets connected to Cushing, Oklahoma.”

Enbridge Inc. has a 27 per cent ownership interest in EEP and a 72 per cent economic interest (41.9 per cent voting interest) in ENF. Enbridge manages the day-to-day operations of, and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities.

— DAILY OIL BULLETIN

Central Canada

Photo: Questerre Energy Corporation

Questerre ramps up a commercial shale gas project in Quebec

Shown here is Questerre’s completion on its St. Edouard shale gas well in the St. Lawrence Lowlands.

Quester re Energ y Cor porat ion continues to report losses as it gears up for commercial shale gas production in Quebec. T he compa ny ’s net loss increased to $5.94 million in the second quarter from a loss of $3.84 million a year earlier. Second-quar ter cash f low was $190,000, while production declined to 620 barrels of oil equivalent per day.

Petroleum and natural gas revenue in the second quarter was $2.81 million, down slightly from $2.97 million a year earlier with oil and natural gas liquids accounting for approximately 50 per cent of the product mix. The debtfree firm’s working capital surplus was $161 million in June, compared to $51 million one year earlier.

“Our goal for this next phase is to have a pad development producing and selling natural gas in Quebec,” said Michael Binnion, president and CEO of the company. “We are currently in negotiations with our partners including Gaz Métro, the pipeline distribution company, for this project. Subject to the final results from the pilot horizontal

well program and the ongoing negotiations, the current time line could see gas on production as early as mid-2011.”

Dur i ng t he second qua r ter, t wo Utica shale horizontal wells were spudded in St. Lawrence Lowlands, Quebec.

The third horizontal well in the program, Fortierville No. 1, was successfully drilled and cased to a measured depth of 3,390 metres, including an approximate 1,000-metre horizontal leg. Drilling also commenced on the fourth well, St. Gertrude No. 1, at the end of June and was completed in early August. This well is programmed at 3,300 metres with a 1,000-metre horizontal leg into the target middle Utica interval.

C omple t ion op e r at ion s f or t he Fortierville No. 1 and St. Gertrude No. 1 wells, are expected to include eightstage fracture stimulations. Contingent on e q u ip m e nt a v a i l a b i l it y i n t h e Lowlands, Questerre anticipates these wells will be completed and tested by year-end.

The company is targeting initial 30 -day average f low rates of

approximately two million cubic feet per day from these wells drilled in the unstructured area of the Utica fairway.

Completion operations on the Gentilly No. 2 well began at the end of the second qu a r te r. T he c omplet ion pr og r a m includes five fracs targeting the middle and lower Utica inter vals. Subject to final testing, results are expected in the third quarter.

Quester re and t he operator a lso finalized long-term testing on the first well in the program, St. Edouard No. 1A . Dr il ling in t he st r uc t ured a rea of the play fairway, initial f low rates f rom t he middle Utica follow ing an eight-stage frac were over 12 million cubic feet per day, with a 30-day average f low rate of approximately 5.7 million cubic feet per day. After 134 days of testing, the well was producing at a rate of approximately 1.4 million cubic feet per day. These initial and stabilized f low rates have exceeded management ’s expectations for this well, Questerre said.

A preliminary analysis of the pressure and production data by Questerre confirms the production curve is most analogous to t he Hay nesv ille shale in Louisiana and Texas. T he results a r e c on si s te nt w it h t he e x te n sive overpressure and natural fracturing encountered in the well, which, in the company’s opinion, contribute to higher initial f low rates with subsequent production at lower stabilized rates.

Quester re recent ly released a Frenc h over v iew of an independent r e p or t on sh a le g a s de ve lopme nt .

T he repor t, titled Moder n Shale Ga s De velopment in the United State s: A Primer, was released in April 2009 by the Ground Water Protection Council, an American association of state regulators whose pr i ma r y pur pose is to promote t he protec t ion of g rou ndwater. Over 90 per cent of their fundi ng comes f rom t he E nv i ron menta l P rotec t ion A genc y a nd t he U. S. Department of Energy.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • OCTOBER 2010

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OCTOBER 2010 • OIL & GAS INQUIRER

2/8/08 11:24:18 AM

International

A low-carbon fuel standard in the U.S. could increase GHG emissions

by Paul Wells

Tankering more oil could generate far more greenhouse gases than importing oilsands synthetic crude.

If the United States adopts a nationwide lowcarbon fuel standard (LCFS), U.S. imports of oilsands crude would shrink, but overall global greenhouse gas (GHG) emissions would increase by up to 19 million metric tons each year, according to a study commissioned by the National Petrochemical and Refiners Association (NPRA).

The report said that a LCFS is likely to discourage U.S. imports of Canadian crude produced from oilsands because of the “higher-lifecycle GHG impacts” and is likely to encourage imports of crude from areas that produce light crude, such as the Middle East. Canadian crude would be diverted to regions not affected

by LCFS. T h is r ipple ef fec t — what t he researchers call a “shuffle” — would create a scenario whereby increased pipeline and tanker transport would be needed to move crude imports to the United States from the Middle East and Canadian exports to Asian countries. This would nullify any potential GHG reductions in the United States, as emissions would increase on a global scale.

“In conducting this technical study, we looked at the most accurate data publicly

available, and the conclusion was clear,” said Joel Trinkle, senior air quality consultant at Barr Engineering Co. and one of the authors of the study. “Crude shuffling under a nationwide LCFS would substantially raise overall greenhouse gas emissions.”

The analysis compares a “base case” developed to assess transport emissions associated with current crude import/ export patterns between Canada and the United States and the Middle East and China, to a “crude shuffle case,” with Middle Eastern crude replacing Canadian imports to the United States and with Canadian crude exports routed instead to China.

The study suggests that this shuffling would double the GHG emissions associated with crude oil transport to and from regions directly and indirectly impacted by the policy.

“A LCFS implemented in the U.S. results in a notable increase in GHG emissions due to the displacement of Canadian crude imports to the U.S. and re-routing of crude imports and exports to accommodate this displacement,” said the study.

“This analysis of the change in crude transport–related emissions accompanying implementation of a LCFS indicates

that the net effect will be a doubling of GHG emissions associated with changes in crude-transport patterns. It indicates an increase in global GHG emissions by 7.1 [million] to 19 million metric tons per year, depending on the extent of resulting Canadian crude displacement.”

NPRA president Charles Drevna said that by “denying the American people access to oil from our friendly neighbour, Canada, a low-carbon fuel standard would raise fuel costs and wipe out millions of American jobs. Now this latest study shows that a nationwide LCFS won’t reduce overall global greenhouse gas emissions — it will actually raise them. These findings simply reinforce NPRA’s long-held belief that a federal low-carbon fuel standard is a policy of all pain and no gain.”

None of the report’s findings come as a surprise to Don Thompson, president of the Oil Sands Developers Group, a non-profit, industry-funded lobby group. “Frankly, the study does not surprise me in the least, because we’ve been telling people for quite some time that the carbon footprint of oilsands crude is fully competitive with the average barrel imported into the U.S. right now. In separate reports, both the Canadian Energy Research Institute and Alberta Energy Research Institute both reported this a year ago,” Thompson said.

“Firstly, there’s no real difference [in GHG emissions from oilsands crude versus other sources imported into the U.S.], and secondly, if you look at the trade relationships and you look at the environmental and other records of the other import options for the U.S., I don’t think there’s ever been a choice for the U.S. — Canada is the natural source for them, and frankly, we can compete with the world.”

Although progress on U.S. climate change policy has slowed to a crawl, the break in the debate might prove beneficial to oilsands producers. “It appears to me that things are on the back burner for now, and I hope that means people are taking their time to examine the record and the facts before they make a decision [on oilsands imports],” Thompson said.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • OCTOBER 2010

57

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58

OCTOBER 2010 • OIL & GAS INQUIRER

onthe

JOB Photo: Christina Ryan, Inez Photography

Careers in the Oilpatch

Garrison Jabs

Age: 25 Education: Open Water Dive Ticket and Unrestricted Commercial Dive Ticket from the Canadian Working Divers Institute Company: Canadian Dewatering LP (2007–10) Location: Fort McMurray, Alberta

What do you do?

Until May, I was a commercial diver in the oilsands tailings ponds at Fort

obstructions from pump intakes, and vacuumed up silt that was building

McMurray. Now I’m in Calgary upgrading a couple of high school courses

one occasion, I hoisted a pump in an isolated area with a helicopter. Every

so I can enrol in mechanical engineering, and would like some day to work

day is different, which is one reason that I enjoyed the work.

up against intakes. We did inspections for tears and other damage. On

as an ROV operator. [Remotely operated vehicles are unmanned underwater robots used for offshore oil and gas and other industries.]

Are the tailings ponds dangerous?

Commercial diving in general is safe nowadays, which wasn’t the case

How did you become a diver?

not long ago. That said, however, it’s important to follow procedures. The

After I graduated from high school in Calgary, I worked and saved until I

tailings ponds are shallow, but under the water is a very soft bed of fine

could afford to enrol at the Canadian Working Divers Institute [located

particles — mostly clay — that’s 8 to 20 feet deep. Also, divers rarely

near Buckhorn, Ont., a two-and-a-half-hour drive northeast of Toronto].

work in pairs. On shore, moving a severely corroded gate valve — 32

The course is only three months long, but it’s expensive. Every day, we got

inches in diameter and weighing about one tonne — would involve three

two hours in the classroom, then 10 to 12 hours on a barge in Catchacoma

workers. I had to move that valve by myself, and that’s typical. A com-

Lake. The instructors are really experienced and the curriculum is com-

plicating factor is radio communication between the diver and the crane

prehensive — wellheads, pipelines, pilings, bridges, salvage and so on.

operator — you can’t both talk at once.

What disqualifies someone as a potential diver?

What did you find rewarding about being a commercial diver at

Physical fitness is basic, of course. Diving is definitely not for anyone

Fort McMurray?

who’s claustrophobic because you sometimes work in confined spaces.

The work is well paid, and it’s not too hard to get another employment

Also, people who require regular medications should be aware that the

contract as long as you maintain industry contacts. Unfortunately, living

increased pressure of being underwater changes some drugs into poisons.

costs there are very high and there’s nothing to do in the evenings except drink. The diving itself is the real reward. You’re almost weightless,

What does a tailings pond diver do on a day-to-day basis?

almost like flying. The only sounds are your [breathing] regulator and the

Canadian Dewatering works with all the oilsands miners. A typical job

gentle movement of water, and in clean water there are these strange

might be removing a large pump so it can be winterized. We often cleared

creatures around you. I'll always love diving.

OIL & GAS INQUIRER • OCTOBER 2010

59

The wheel has been around since 3500BC, but was first patented in 1791. calling all innovators!

bring out your gizmos,

gadgets, inventions and technological

breakthroughs… big or small, we’re interested in the latest and greatest oil and gas technologies.

6

And while you can’t reinvent the wheel, you and your invention can grace the pages of the December issues of Oil & Gas Inquirer and New Technology Magazine. Get your nomination in today!

a total of 6 Technology Stars will be awarded in the following categories: ★ best exploration technology ★ best drilling technology (2 awarded) ★ best production technology (2 awarded) ★ best hse technology

Don’t delay! Nominate at www.newtechnologystars.com

www.newtechnologystars.com competition closes october 15, 2010. to be eligible, a company must operate in canada, with its product or service deployed here.

TOOLS

Helically Wound Galvanized Steel Cords

OF THE TRADE A LOOK AT NEW TECHNOLOGIES

FlexCord Linepipe Barrier Layer

High Density Polyethylene Jacket

Photos & illustration: Flexpipe Systems

High Density Polyethylene Liner

FlexCord Linepipe was developed in response to the industry shift from vertical to horizontal activity.

Who is Flexpipe Systems?

Flexpipe Systems, a division of ShawCor Limited, is the market leader in continuous pipeline technology, providing complete engineering and application resources to its clients. Flexpipe Systems’ spoolable composite pipeline systems are used for oil and gas gathering systems, water disposal, CO2 injection pipelines and other applications where a corrosion-resistant, high-pressure pipeline is required.

What is FlexCord Linepipe?

FlexCord Linepipe is a composite pipeline system designed for pipeline applications with severe pressure cycling. The benefit of FlexCord is that its middle [strength component] layer is constructed from galvanized steel cords instead of glass fibres. FlexCord Linepipe is available in three- and four-inch internal diameters and has a maximum allowable operating pressure of 10,342 kilopascals [1,500 pounds per square inch] and a maximum allowable operating temperature of 55 degrees Celsius. This allows FlexCord to meet the needs of a wide variety of oilpatch applications, including many oilfield water transfer or highly corrosive and injection/disposal applications.

What are the competitive advantages of this product?

In today’s world of volatile commodity pricing, the requirement to get wells online in a timely fashion warrants spoolable technology. Operators with a backlog of wells that have been drilled but not tied in can get their wells on stream faster and more cheaply with this type of product. FlexCord Linepipe helps clients lower the cost of their pipeline projects, reduce the environmental impact

caused by pipelining and increase production rates through quick installation of new lines or rehabilitation of corroded steel lines.

FlexCord’s structural integrity is provided by the inner layer of helically wound steel cords. The use of galvanized cords provides better corrosion resistance than the bare steel used in other composite technology.

The internal diameter of three- and four-inch FlexCord Linepipe is larger than that of its nearest composite competitor. This means that FlexCord Linepipe has a greater flow area, which can move more fluid or gas through the line. Flexpipe Systems’ applications engineering team works directly with clients to determine specific flow requirements and will provide the right pipeline solution to address the client’s volume/flow rate needs.

Has FlexCord Linepipe been deployed in the field?

FlexCord Linepipe has been approved as a routine status application at the ERCB [Energy Resources Conservation Board] for services with zero parts per million of hydrogen sulphide. Flexpipe Systems installed its first FlexCord Linepipe project near Hays, Alta., immediately after the product’s commercial release.

The installation of the FlexCord Linepipe was completed on time and on budget.

What do you see as the future market for this product?

The recent upstream activity shift from vertical toward more horizontal drilling [and from gas production to oil] results in a larger market for pipeline with greater cyclic capabilities. FlexCord Linepipe allows Flexpipe Systems to better serve the growing demand in North and South America for large, cyclic, high-pressure, small-diameter pipeline.

Information supplied by: Christine Wilson, Communications and Brand Manager, Flexpipe Systems

OIL & GAS INQUIRER • OCTOBER 2010

61

CARTOON GOES HERE

Advertisers' Index 1174365 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . 27 1214848 Alberta Ltd . . . . . . . . . . . . . . . . . 45 & 49 Accuform Welding Ltd . . . . . . . . . . . . . . . . . . . .56 Action Health And Safety Services . . . . . . . . . 30 Alger & Associates Inc . . . . . . . . . . . . . . . . . . . 52 Aman Building Corp . . . . . . . . . . . . . . . . . . . . . . 28 Annugas Compression Consulting Ltd . . . . . . . 20 Bear Slashing Ltd . . . . . . . . . . . . . . . . . . . . . . . 38 Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . 56 Bilton Welding and Manufacturing Ltd . . . . . . . 50 Black Sivalls & Bryson (Canada) Ltd . . . . . . . . . 30 Brother's Specialized Coating Systems Ltd . . . 42 Brownlee LLP . . . . . . . . . . . . . . . . . . . . . . . . . . 58 Canadian Association of Petroleum Producers (CAPP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . 11 CARES Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Certified Management Accountants Of Alberta . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Crompton Western Canada Inc . . . . . . . . . . . . . 24

62

OCTOBER 2010 • OIL & GAS INQUIRER

D & R Equipment Ltd . . . . . . . . . . . . . . . . . . . . . 45 Dean's Pump Service Ltd . . . . . . . . . . . . . . . . . 46 DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Diversified Glycol Services Inc . . . . . . . . . . . . . 50 Eagle Drilling Services Ltd . . . . . . . . . . . . . . . . . 16 EITI Electrical Industry Training Institute . . . . . 52 Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . 34 Gaugetech Inc . . . . . . . . . . . . . . . . . . . . . . . . . . 41 General Motors of Canada Ltd . . . Inside back cover Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . 34 LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . 46 Lockhart Oilfield Services Ltd . . . . . . . . . . . . . 33 LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . 38 MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Meridian Mfg Group . . . . . . . . . . . . . . . . . . . . . . 17 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . 34 Northgate Industries Ltd . . . . . . . . . . . . . . . . . 34 Northstar Energy Services Inc . . . . . . . . . . 4 & 23 Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . 32 Oil Lift Technology Inc . . . . . . . . . . . . . . . . . . . . 46

OilPro Oilfield Production Equipment Ltd . . . . 58 Oomph Events . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . 27 Platinum Energy Services Corp . . . . Outside back cover Platinum Grover Int. Inc . . . . . . . Inside front cover PrintWest Communications . . . . . . . . . . . . . . . 38 Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . 3 Prostate Cancer Canada Network . . . . . . . . . . 52 Silverado Oilfield Ventures Ltd . . . . . . . . . . . . . 28 Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . . 37 Systech Instrumentation Inc . . . . . . . . . . . . . . 30 TCA Marketing Ltd . . . . . . . . . . . . . . . . . . . . . . . 7 The Motor Company . . . . . . . . . . . . . . . . . . . . . 29 Trans Peace Construction (1987) Ltd . . . . . . . . 40 TransGas Limited . . . . . . . . . . . . . . . . . . . . . . . 27 Vertigo Theatre Society . . . . . . . . . . . . . . . . . . 40 V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . 42 Waydex Services LP . . . . . . . . . . . . . . . . . . . . . 25

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