Oil & Gas Inquirer February 2010

FEBRUARY 2010 � $6.00

Keeping readers regionally informed

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Here Comes THe

dragon Canada's oilfield manufaCTurers faCe a grim CHallenge from CHina

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• BONNYVILLE • LLOYDMINSTER • MEDICINE HAT • FARMINGTON NM • BRISBANE AU • OIL & GAS INQUIRER • February 2010

5

Table of Contents

Keeping readers regionally informed

F E A T U R E S

12

The Chinese dragon

18

Greening Turner Valley

22

A Bakken two-step

by Mike Byfield

Canada's oilfield manufacturers face a truly formidable challenger

by Mike Byfield

Jim Gordon specializes in cleaning up Alberta’s oldest oilfield

by Mike Byfield

Rotex combines fresh water supply with produced water disposal in a single facility

With all the uncertainty about the economy, look for our Recession to Recovery logo for coverage on how companies are handling the downturn, preparing for the rebound, and, in some cases, even thriving.

6

February 2010 • OIL & GAS INQUIRER

Table of Contents

R E G I O N A L

25

N E W S

British Columbia

37

• B.C. government’s incentives will boost

• Q 3 service sector revenue improves

field activity in 2010

27

over Q2 but falls $1.8B from 2008 • Precision plans to cut capital spending

Northwestern Alberta/Foothills • Alberta’s $384M auction more than doubles its land revenue for 2009

and decommission 38 drilling rigs

43

Bakken expansion program

and Birchcliff

Northeastern Alberta

45

• Laricina Energy pushes ahead with its

achieves its first step forward

35

a need for Arctic gas supply

47

oilsands but take the money

Central Canada • Canada’s gas export decline was the

Central Alberta • Quebec and Ontario dump on Alberta’s

Northern Frontiers • TransCanada CEO Hal Kvisle still sees

Saleski carbonate project • Sunshine’s carbonates pilot project

Saskatchewan • Reliable Energy slowly advances its

• Montney formation attracts Galleon

31

Southern Alberta

biggest since at least 1985

49

International • Savanna announces Australian deal along with its 2010 capital plans

I N

10

E VE R Y

I S S U E

Statistics at a Glance

53

• Completions data, spot gas prices, gas

Tools of the Trade • Hex-Hut Shelter Systems Ltd. has

storage, drilling activity, and more

created a line of unique portable welding shelters for pipeline and

51

other oil and gas fieldwork.

On The Job • As a field technician with Solar Turbines, Ally McLean brings electronics and

54

Political Cartoon

mechanical skills to maintaining and troubleshooting complex technology.

Cover Design: Aaron Parker

OIL & GAS INQUIRER • February 2010

7

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Editor’s Note Vol. 22 No. 2 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com

Mike Byfield | mbyfield@junewarren-nickles.com

Dealing with China

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Cristian Ureta | cureta@junewarren-nickles.com OFFICES Calgary

200, 816 – 55 Avenue N.E. | Calgary, Alberta T2E 6Y4 Tel: 403.209.3500 | Fax: 403.245.8666 Toll-Free: 1.800.387.2446

Calgary North 300, 5735 – 7 Street N.E. | Calgary, Alberta T2E 8V3 Tel: 403.265.3700 | Fax: 403.265.3706 Toll-Free: 1.888.563.2946 Edmonton 6111 – 91 Street N.W. | Edmonton, Alberta T6E 6V6 Tel: 780.944.9333 | Fax: 780.944.9500 Toll-Free: 1.800.563.2946

Alberta’s most underplayed energy news story of 2009 occurred in August, when PetroChina paid $1.9 billion for a 60 per cent stake in Athabasca Oil Sands Corp. The stateowned upstream producer thus acquired three billion net barrels of bitumen, and almost certainly it’s hoping that the oil will end up in its own country.

Even less attention has been given to China’s growing role as an oilfield supplier, the subject of this month’s cover article in Oil & Gas Inquirer. What does China, as a possible customer and a formidable competitor, mean for the western oilpatch?

Washington’s accumulated debt and trade deficits came to a head in December at the United Nations–sponsored climate conference in Copenhagen. U.S. President Barack Obama utterly failed to impose carbon dioxide restrictions on the global economy.

Blocking Obama was Chinese premier Wen Jiabao, whose government has authorized PetroChina to invest US$30 billion in overseas petroleum development.

To prosper in the emerging world trade order, Canadians will need to maximize their exports, notably in energy. To achieve that goal, several realities should be grasped: • T he Unites States remains our key partner over the long haul. In the short term, however, Obama will only hinder Canada, especially when it comes to hydrocarbons. Never forget that this president campaigned against the North American Free Trade Agreement.

• China is willing and able to finance energy deals. Also eager to buy are India, Japan, and other Asian states.

• At this time, very little of our oil can reach Asia. To service that market, our federal and provincial governments should ensure that additional pipeline capacity is developed over the Rockies.

• I f PetroChina needs assistance in sponsoring an export pipeline, provincial royalty bitumen could be committed to ensure sufficient supply. In exchange, Albertans should insist on shipping refined products, not raw crude.

In another sense, China is less than cooperative with its trading partners. Its Communist government fosters huge trade surpluses and foreign currency reserves.

According to some analysts, Chinese workers are kept underpaid as a means of increasing Chinese power. So our clothing, electronics, and much more—including oil and gas equipment—are increasingly made in China. Cheap shoes are nice, but exactly how does this scenario play out when the bills really arrive?

Free trade is supposed to maximize benefits for all, assuming everyone works by the same rules. However, steel-makers and many others insist that China’s Communist dictators and their state-directed economy don’t comply with those rules. North Americans need to conduct a top level discussion on this topic, with the goal of giving reasonable protection to our own workers and companies.

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I S S U E

with producers racing to horizontally redrill and

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

multi-frac a classic formation. Also, Oil & Gas

email mbyfield@junewarren-nickles.com.

Inquirer examines the growing role of coiled

In fact, feel free to sound off about any

tubing in well completions.

concern at all—that’s a personal invitation.

OIL & GAS INQUIRER • February 2010

9

Stats

FAST NUMBERS

$19.6

AT A GLANCE

billion

Alberta’s net contribution to federal coffers in 2007 (taxes sent to Ottawa minus federal spending in the province), totalling more than $22,000 per family of four. Energy activity makes this possible.

$4.1

billion

Manitoba’s net benefit from federal taxation in 2007, equal to nearly $14,000 per family of four, the most recent figures available from Statistics Canada.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

TOTAL

MONTH

OIL

GAS

DRY

SERVICE

TOTAL

Jan 2009 Feb 2009 Mar 2009

156 116 321

606 899 979

96 120 317

858 1,135 1,617

Jan 2009 Feb 2009 Mar 2009

248 269 433

813 1,060 1,121

70 113 165

47 36 86

1,178 1,478 1,805

Apr 2009 May 2009 Jun 2009

111 71 36

344 187 143

140 53 42

595 311 221

Apr 2009 May 2009 Jun 2009

111 71 177

342 187 211

61 46 45

12 35 27

526 339 460

Jul 2009 Aug 2009 Sept 2009

79 101 146

178 212 155

77 80 78

334 393 379

July 2009 Aug 2009 Sept 2009

79 250 146

31 267 155

6 36 45

3 37 9

119 590 355

Oct 2009 Nov 2009 Dec 2009

132 169 121

160 212 127

77 116 35

369 497 283

Oct 2009 Nov 2009 Dec 2009

331 382 283

196 244 138

32 68 34

12 10 13

571 704 468

Wells Drilled In British Columbia

Wells Drilled In Saskatchewan

Source: B.C. Oil and Gas Commission

Cumulative to January 8, 2010 Source: Saskatchewan Energy & Resources

MONTH

WELLS D R I L L E D

CUMULATIVE *

Jan 2009 Feb 2009 Mar 2009

125 117 75

125 242 317

Apr 2009 May 2009 Jun 2009

33 26 19

350 376 395

Jul 2009 Aug 2009 Sept 2009

34 36 38

429 465 503

Oct 2009 Nov 2009 Dec 2009

29 39 44

532 571 615

OIL

GAS

OTHER

D RY

T O TA L

Vertical Wells

Lloydminster Kindersley Swift Current Estevan

3 0 0 1

0 0 11 0

0 0 0 1

0 1 1 0

3 1 12 2

0 3 2 4

0 0 0 0

0 0 0 1

0 0 0 0

0 3 2 5

3 3 2 4

0 0 11 0

0 0 0 1

0 1 1 0

3 4 14 5

Horizonal Wells

Lloydminster Kindersley Swift Current Estevan Total Wells

Lloydminster Kindersley Swift Current Estevan

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February 2010 • OIL & GAS INQUIRER

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 3.5

6.0

$5.23/GJ Total vol.: 1,150 TJ Transactions: 126

5.5

5.0

in the United States

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Dec 30

Jan 6

Jan 13

2.61 Tcf Year ago: 2.58 Tcf 5-year avg: 2.61 Tcf

3.0

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Jan 20

Dec 18

Dec 25

Jan 1

Jan 8

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada January 14, 2010 Source: Rig Locator

Alberta December 2009 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

(Per cent of total)

Western Canada Alberta

ACTIVE

354

205

559

63%

British Columbia

87

28

115

76%

Manitoba

11

2

13

85%

Saskatchewan

68

46

114

60%

WC Totals

520

281

801

65%

0

2

2

0%

Northwest Territories

OIL WELLS

Alberta

GAS WELLS

Dec 09

Dec 08

Dec 09

Dec 08

Northwestern Alberta

11

154

44

669

Northeastern Alberta

29

172

3

105

Central Alberta

57

226

29

422

Southern Alberta

24

53

51

710

121

605

127

1906

TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada January 14, 2010 Source: Rig Locator

Alberta December 2009 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE

Western Canada Alberta

205

559

63%

22

12

34

65%

8

1

9

89%

Saskatchewan

125

54

179

70%

WC Totals

470

329

799

59%

0

2

2

0%

British Columbia

Manitoba

Northwest Territories

COALBED METHANE

Alberta 354

Jan 15

BITUMEN WELLS

Dec 09

Dec 08

Dec 09

Dec 08

Northwestern Alberta

0

18

4

18

Northeastern Alberta

0

0

29

165

Central Alberta

6

106

22

111

Southern Alberta

12

120

0

0

TOTAL

18

244

55

294

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OIL & GAS INQUIRER • February 2010

11

The Chinese dragon Canada’s oilfield manufacturers face a truly formidable challenger

by Mike Byfield

I

n China, the traditional dragon symbolizes good fortune. Westerners, in contrast, have always seen the flying fire breathers as threats. In the case of oil and gas manufacturing, both views happen to be appropriate. China’s expanding exports of drilling rigs, pumpjacks, and other petroleum technology are generating foreign revenue and influence.

Never before have North America’s onshore equipment makers faced a challenger of this strength. Chinese firms offer a comprehensive range of exploration and production components at prices perhaps 20–30 per cent below their Canadian and American competitors.

12

February 2010 • OIL & GAS INQUIRER

Feature

OIL & GAS INQUIRER • February 2010

13

Feature

Luke Lu manages North American marketing for Pemsco Ltd., the Calgarybased subsidiary of China Petroleum Technology & Development Corporation.

CPTDC in turn is the technology-trading arm of the state-controlled China National Petroleum Corporation. “We have submitted a business case for opening a facility in Alberta. This centre would handle quality testing, parts inventories, repairs, and training. In future, it might also fabricate components that are too large to ship from China, mainly for the oilsands,” Lu says.

“No decision has been made by our head office yet, but I am optimistic that we will proceed within a year.”

CPTDC’s export sales were as strong in 2009 as 2008, running at about US$2.3 billion annually. The company supplies customers in 66 countries from 35 overseas offices, 4 warehouses, and 7 maintenance centres throughout the world. Its parent firm is the world’s largest oil and gas operator in terms of personnel, with more than one million employees in the

upstream, pipeline, downstream, and petrochemical sectors.

Pemsco is planning its Canadian expansion despite a large annual sales drop in this country, from about $10 million in good years to a mere $250,000 in 2009. “The Canadian market has suffered more than the United States, where demand started picking up in September,” Lu notes. “However, our senior management in China takes a long-term approach to investment and CPTDC believes in the future of the Canadian industry. Our customers can count on us to be here for the long run.”

Another Chinese manager says his nation’s presence is already strong in the western Canadian oilpatch. (This individual, who’s not authorized by his employer to comment publicly, goes by the pseudonym Pang Zi, Mandarin for Tubby.) “A few fully assembled drilling rigs have been sold in the U.S., but so far none in Canada.

Instead, a lot of rig components come here from China,” he reports. “Although very

China’s pumpjacks and drilling rigs started to sell overseas when manufacturers met API standards.

14

February 2010 • OIL & GAS INQUIRER

few rigs are being built this year, I think a new made-in-Canada rig consists of up to 80 per cent Chinese parts.”

Duane Mather, president of Nabors Canada, says his company assembles its drilling rigs here but buys “the right pieces” from China. “We’ve purchased pumps, some drawworks, masts, virtually some of everything except our AC drives, which are always designed and built in house,” the Calgarian says. “We must buy in China or our capital equipment costs would not remain competitive.”

Initially, the Calgary-based drilling contractor found it essential to closely supervise the manufacture of parts in China. “Their skills and quality control were not equivalent to North American standards. We went there solely because prices were 50–60 per cent lower,” Mather says. “Chinese manufacturing costs have risen pretty quickly over the past two or three years, but they’re still significantly less than here. Meanwhile, the quality has gotten much better. We still test every

Feature

The president of a Canadian pump manufacturing firm, speaking on a notfor-attribution basis, says his firm has developed patent-protected technology that lowers the full-cycle cost of its pumps over the operating life of the equipment.

“Unfortunately, the initial purchase price of our products is higher than Chinese pumps. Convincing a producer to accept a higher price tag is difficult, even if that initial investment will pay off later. Even when times were good, a higher first cost was a hard sell, and it’s worse now,” he says.

Unt i l now, on shore tec h nolog y remained firmly rooted on this continent despite the fact that petroleum has long been produced outside North America— for well over a century in Russia, Iran, Indonesia, and Mexico, for instance. Even the Soviet Union, although scientifically advanced in some industries, used strikingly primitive upstream equipment. So how did the People’s Republic of China forge itself into an oil and gas manufacturing juggernaut?

The nation achieved its first significant petroleum production during the 1960s, when a giant oilfield was found in its northeastern region. Production developed around the city of Daqing, initially with Soviet-style equipment. Lu’s own life and career help illustrate his country’s forward momentum. “Thirty years ago, a

“We must buy in China or our capital equipment costs would not remain competitive.”

Duane Mather, President, Nabors Canada

Photo: GN Solids Control

component and we do get a surprise once in a while but the improvement is very noticeable.”

Roge r Souc y, pr e side nt of t he Petroleum Services Association of Canada, acknowledges that Chinese oilfield suppliers are formidable rivals. “Their primary advantage is well understood—labour costs there are a small fraction of ours,” he comments. “Canadian companies must counter that factor with research and development, where this country still leads China. But the competition is going to be difficult; there’s no way of getting around that fact.”

Pang Zi agrees that North America still has a big lead in research and development capability. “In China, patents cannot be enforced, so R&D investment often cannot be recovered. Even the government cannot protect its R&D results. As a result, our manufacturing goals focus on making equipment that’s simple and very durable. We also work with foreign companies who have technology.”

GN Solids Control says it’s one of 10 Chinese firms that design and manufacture solids control systems.

OIL & GAS INQUIRER • February 2010

15

Feature

rising, but the economy continues to make great progress.”

Lu uses mud pumps as an example of how Chinese engineers acquired modern manufacturing skills. “During the 1980s, CNPC purchased more than 500 mud pumps from an American company. As part of that deal, we received the drawings and personnel training—it was a complete technology transfer,” he recounts.

“Since that time, CNPC has manufactured many thousands of mud pumps, including 700 for Precision Drilling.”

To date, the Daqing field has produced more than 10 billion barrels of crude. Its pumpjacks have been made by a CNPC subsidiary based in the city.

Photo: Joey Podlubny

working family like mine received three or four ounces of pork a month, and just two ounces of cooking oil. The annual clothing allowance was just as poor,” he recalls.

In 1980, China’s Communist regime introduced market-oriented reforms. A professional engineer, Lu advanced to chief of quality control in the factory that makes drilling rigs for China National Petroleum Corporation (CNPC). “In 1997, I was earning a little less than US$200 per month plus housing and other benefits, which was a good salary,” says the marketing manager, who has lived on this side of the Pacific Ocean for the past 12 years.

“Today, that position is worth US$700– US$800 a month. Our labour costs are

Nabors Canada says it has imported every type of Chinese rig part except its proprietary AC drives.

16

February 2010 • OIL & GAS INQUIRER

“The population is the same size as Calgary, about one million, and making pumpjacks is the main manufacturing industry there,” says Pang Zi, a Chinese-trained engineer who now lives in North America. “The central factory complex has a footprint of about six million square feet.”

A nnual manufact ur ing capacit y is estimated at 6,000 to 8,000 pumpjacks, depending on unit size. There’s no lack of customers, and the Chinese government is in the process of doubling capacit y over five years. The countr y now has smaller pumpjack makers as well, privately held firms that have spun off from the governmentowned operation. “In the early days, we could not get good machine tools, and materials were also deficient,” Pang Zi says. “Now the equipment used by our factories is global quality and so are the steels and other materials.”

Chinese steel has become a contentious trade issue. The people’s republic has been sanctioned in the United States, Europe, and Canada, on the grounds that the price of exported oil country tubular goods (OCTG) in export markets has been set below what they would sell for in the country’s domestic markets. In November, the Canada Border Services Agency ruled that China is dumping and subsidizing certain OCTGs in this country. Federal duties ranging up to 182 per cent have been imposed.

Chinese seamless casing with an outside diameter up to 11 ¾ inches was already subject to a finding in 2008 by the Canadian International Trade Tribunal. The CITT is also investigating alleged dumping of well casing and tubing in other categories. That inquiry was triggered by a joint complaint from Canada’s principal steelmakers, Tenaris Canada, Evraz Inc. NA Canada, and Lakeside Steel Corporation.

Ron Bedard, president and COO of Ontario-based Lakeside, says the Ontario-based company is “committed to ensuring imports into the Canadian market are fairly traded.” The petroleum industry is considered a crucial market

by American and Canadian steel firms.

Lu responds that the import duties levied against China will raise tubular prices for western Canadian oil and gas producers.

“The main benefit of those duties will go to foreign-owned companies who are China’s competitors here,” the Pemsco engineer argues.

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In making the steel that goes into oilfield pipe and equipment, China has no obvious competitive advantage. Labour does not constitute a large percentage of steel cost, and the country imports iron ore. Yet documentation provided to federal agencies by Canadian-based tubular producers portrays China as fiercely aggressive in the industry. Its government sector—at the national, state, and municipal levels—has made large investments over the past five years, boosting China’s share of global steelmaking to 50 per cent from 20 per cent. Over the same period, the country’s internal demand has increased from 20 per cent to about 25 per cent of the world total.

Canada’s steel industry, mostly foreignowned but based here, argues that China has violated investment regulations laid down by the World Trade Organization.

One Canadian executive, speaking on a not-for-attribution basis, sums it up: “China overshot the world market with its steel investments and is dumping its surplus.

That trading strategy is aimed primarily at protecting jobs. To Chinese governments, employment and political stability are more important than profitability.

Fortunately, the Canadian steel industry is positioned to bear the considerable expense required to fight this type of trade case. I’m not sure other oilfield manufacturers are as well organized.”

Beyond tubulars, labour expense is definitely a key factor in most oilfield manufacturing. Pang Zi notes that Chinese technicians are now as well-trained as their North American counterparts, and in his opinion they’re often more motivated.

“A Chinese team can accomplish in a single day what I sometimes see being done here by the same number of workers in three or four days,” the engineer says. “Right now, China is a train that can’t be stopped.”

But perhaps that train should be slowed down a little. Andy Wright, founder of Torque Control Systems Ltd., has done business in China. “Our company makes oilwell components in Edmonton.

We pay our skilled workers $30 per hour, and the comparable wage rate in China is $1,” Wright says. “Everyone recognizes the benefits of trade. Still, when North Americans are competing against countries with very low wage rates, I believe it would be reasonable to charge an import duty that reflects at least a percentage of that difference.”

3 403.293.7333 www.HeX-Hut.com OIL & GAS INQUIRER • February 2010

17

Feature

Greening Turner Valley CanEra Resources' Jim Gordon has devoted much of his career to restoring lands around Turner Valley.

Jim Gordon specializes in cleaning up Alberta’s oldest oilfield

by Mike Byfield

W

hen it comes to upstream petroleum operations, engineers and investors want cheaper.

Neighbours and regulators demand cleaner. Striving to satisfy those conflicting claims is the job of ecological specialists like Jim Gordon, environmental manager at CanEra Resources Inc. “Our colleagues in other disciplines tend to treat us as overly enthusiastic greens, especially when we’re competing for our share of the company budget,” Gordon says. “On the other hand, an upset landowner or green protester sees people like me in the opposite 18

February 2010 • OIL & GAS INQUIRER

light—to them, we are just ‘dirty oil,’ not environmentalists at all.”

So how does an eco-oilman view himself? “Most environmental professionals get into this field to make a difference, and I believe we’re steadily achieving improvements that benefit everyone, and com-panies are seeing real value in wellmanaged environmental programs,” the CanEra manager responds. In fact, most of today’s oilfield waste treatment technology did not exist when Gordon first fell in love with Mother Nature, fishing and hunting with his father in the mountains around

Cranbrook, British Columbia. Nor were environmental degrees available in the early 1980s, when he attended university.

“Instead, I majored in geography, studying soils, organic chemistry, and related physical sciences,” the Calgarian says.

Early in his career, Gordon spent seven years working with Jim Lore, widely respected as the “grandfather” of agricultural consulting in Alberta and a principal influence behind the agricultural program at Olds College. “I managed remediation work in Alberta north of the Yellowhead Highway, mostly for Gulf Canada

Feature Photo: Rachel Imrie, Illuminessence Designs

[now ConocoPhillips Canada, one of the country’s top three natural gas producers].

That’s also when I first got acquainted with the Turner Valley district,” he says.

Later, he went to work for Pembina Resources Limited, then the dominant operator in Turner Valley. In 1997, Pembina spun off its upstream assets to Talisman Energy Inc. As one of more than 2,000 personnel in Calgary, Gordon supervised Talisman’s North American remediation and reclamation operations.

“However, I continued to stay involved with our Turner Valley assets, cleaning up old flare pits and historical spills,” he comments. On Nov. 27, Talisman sold its southern Alberta properties to CanEra. In large part due to his interest in Turner Valley,

Gordon decided to join the newly minted junior at the ground level.

Turner Valley is Alberta’s oldest oilfield, and its natural gas production dates back even further to 1914. Early environmental practices were not so much primitive as non-existent. During the 1920s, nearly a trillion cubic feet of natural gas was burned as an unsaleable byproduct of liquids production. Reportedly, Calgarians living 60 kilometres to the northeast could sometimes read a newspaper at midnight by the light of those sulphur-reeking flares. Decade after decade, spills went untracked. Produced water was typically buried just deep enough to prevent the oil residue from gumming up agricultural machinery. Local farmers and ranchers took advantage of oilfield waste pits to dump all manner of their own pollutants.

People at the time were concerned about the flaring. That self-evident waste prompted the formation of the Turner Valley Conservation Board in 1932, followed six years later by the regulatory agency now called the Alberta Energy Resources Conservation Board. Natural gas markets were developed as quickly as pipelines could be constructed on an economic basis to distant cities in the United States and eastern Canada.

Soil and water contamination, in contrast, was not considered a significant problem until much later. That attitude was understandable. The foothills meadows around Turner Valley have always ranked among Alberta’s lushest, with hay growing right up to pumpjacks perched picturesquely against the Rockies. With sour gas production fully cleaned up, prosperous families by the hundreds constructed acreage homes in the area, generating some of the province’s highest real estate values.

Still, Gordon says, the beautiful setting does not justify complacency. “We

now understand cumulative effects and other pollution hazards that simply weren’t recognized by previous generations,” the CanEra manager explains.

“The oil and gas industry knows that it’s both safer and less expensive to prevent contaminants from being released in the first place. When contamination does occur, it’s more efficient to clean it up immediately rather than let the contaminants disperse into the environment.

Finally, we accept the responsibility to remediate historical problems.”

Fortunately, Turner Valley benefits from several positive historical factors.

“Virtually all of the contamination in the area dates back to earlier times. Operators have been following best practices there for quite a while,” Gordon says. “In the earlier period, companies used few of the exotic chemicals that are common today. Drilling mud, for instance, usually consisted of local bentonite clays and fresh water, an environmentally harmless mixture. Also, produced water [i.e. water flowing from underground formations with oil and gas] in Turner Valley is relatively fresh. Elsewhere in Alberta, produced water is often much saltier, which can damage soils and aquifers, and is difficult to remediate.”

Fortunately, Gordon adds, most residents in the Turner Valley area take a neighbourly attitude to the industry, particularly those with deep local roots.

“CanEra’s management team acquired its assets here with eyes wide open,” the environmental manager says. “Strong communication with all stakeholders is critical; that’s understood. We also know that occasionally an individual will be more difficult so some extra effort will be required from time to time. Basically, our company will behave responsibly and people will come to accept us as a member of the community in good standing.”

OIL & GAS INQUIRER • February 2010

19

Feature

Canada's land remediation standards are

H

istorical contamination is common to industries and communities across Canada. In response, the Canadian Council of Ministers of the Environment (CCME) has developed a classification system for the assessment and remediation of contaminated sites. Those standards—among the most stringent in the world—have been adopted by Alberta as Tier 1 standards. The Alberta Tier 1 standards and CCME code will continue to evolve gradually as new remediation science and technologies are developed.

Petroleum producers in Alberta are required to meet Tier 1 standards before they can legally abandon a property. Until then, the property remains an environmental liability, affecting a company’s share price and balance sheet. When the decision to abandon is made, the first step involves searching all records for physical targets that will have to be assessed in the field, such as wellsites, gathering pipelines, tanks, and flare pits.

In the second phase, a coring rig takes soil samples, which will be analyzed by an accredited independent laboratory.

On the basis of that analysis, the producer will work out a detailed remediation plan. Some contaminants are technically much easier to remove than others. For example, natural bacteria found in native soils will swiftly gobble up light oils once the material is exposed to oxygen in systems commonly referred to as “bio-piles” or “landfarms.” But even the most voracious of these “bugs” may take decades to digest heavier crude remnants.

In its remediation strategy, a producer must choose whether it will treat the affected soils on site or haul the dirt away to an accredited disposal facility. Transporting soils can be very costly if long distances are involved, which is frequently the case. Typically, hauling makes sense for small quantities of material unless on-site remediation is straightforward.

20

February 2010 • OIL & GAS INQUIRER

tough If larger tonnages are involved, a company may choose to take the investment risks involved in on-site remediation. In that case, there are two basic regulatory options: • T he site can be remediated to the point of complying with the CCME’s universal standards for all sites. Those standards are extremely demanding and hence the site’s remediation may become very expensive.

• T he company can invest in research, using state-of-the-art scientific methods to identify all potential hazards to soil, water, animals, plants, humans, and so forth at its specific site. Based on that data, a regulatory application can be filed in support of a lower standard of compliance appropriate for that site. The research required for a site-specific remediation plan is invariably expensive. Worse, that research may or may not lead to a regulatory decision in favour of a lower compliance standard.

In fact, the only risk-free strategy in many cases is hauling the stuff away for disposal, albeit more often than not at exorbitant expense. If site-specific remediation tools are applied but fail to remove the contaminants, the abandonment liability remains on the company’s books.

In economically hard times, a producer whose contaminated property is located where no one is likely to complain— say, an acre or two of shortgrass prairie at Hemaruka—may well decide to leave well enough alone for a while. Eventually, natural gas prices will rise or maybe a scientist will devise a better solution.

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21

Feature

A Bakken two-step

Rotex combines fresh water supply with produced water disposal in a single facilityy Mike Byfield

I

Photo: Rotex Energy Ltd.

n January, Rotex Energy Ltd. opened its new oilfield waste management facility at Willmar, Saskatchewan, northeast of Estevan. The site includes a disposal well, processing of tank and vacuum truckloads, and a frac water supply. “We’re located in the southeastern part of the province, and drilling activity is expanding in that direction,” says Kevin Baumann, president of the start-up company. “Rotex is the first to combine water disposal with a supply of consistent fracturing compatible water for well completion, which is in high demand. Our safe and user-friendly facility design allows for continual compliance with industry regulations.”

Rotex has been designed as more than a one-trick pony. In British Columbia, the private firm is developing a disposal well

Rotex President, Kevin Baumann 22

February 2010 • OIL & GAS INQUIRER

just south of the Northwest Territories to service producers in the Horn River Basin. Baumann, a Métis himself, is working on that project with Beaver Enterprises, an aboriginally owned company of the Acho Dene Koe. The ADK will own a percentage of the facility after its capital cost is paid out.

The ADK are also partnering with Rotex to develop a landfill site on the band’s traditional lands in the Northwest Territories.

For lack of disposal facilities, large quantities of solid oilfield waste have been awaiting disposal in the region for many years.

“Producers would like to clean up that backlog and we can make that job economically feasible,” says Baumann, a former rig hand and truck driver who turned entrepreneur in the early 1980s.

Geotechnical studies and related regulatory assessment have already begun on the B.C. disposal well. This winter, Rotex completed freezing down wellsite access in preparation for wellbore recompletion for water disposal. Although Baumann isn’t in a position to discuss any plans to develop an alternate source of fracturing water or the possibility of water recycling in the region, he’s well aware that producers require massive supplies of water in future as they proceed with hundreds of multi-stage horizontal fracs.

Rotex sees water as critical to its southeastern Saskatchewan strategy as well.

“Frac water has to be consistent. Right now, producers are taking water from towns, streams, and dugouts,” Baumann says.

Very roughly, he estimates annual oilfield demand for water in the region at six million barrels, much of it for fracs. “That’s a lot of pressure on the available supply. Right now, a landowner can get revenue for water from his dugout, although there is no guarantee of quality, consistency, temperature, or sufficient volume.”

In the future, Baumann sees a market for large volumes of compatible and consistent water for large multi-stage fracturing being done in the area.

In 2007, as part of developing Rotex’s plan for the area, the 47-year-old entrepreneur identified an oil well suitable for water disposal. Its modern casing and cementing are in good shape. The well is approximately 1,500 metres deep in the Mannville formation (and far beyond any aquifer that would be used for agricultural water). The reservoir rock has excellent permeability and porosity, suitable for rapid water disposal.

Nearby, Rotex found a source well, its water slightly salty but fresh enough for fracturing. Baumann says this water has been confirmed by fracturing companies

Photo: Rotex Energy Ltd.

Feature

Rotex Energy says its new facility at Willmar will reduce pressure on scarce surface water resources in southeastern Saskatchewan.

as suitable. Another element in his business strategy: producers will receive an oil payment for crude recovered from their waste streams.

Last summer, Rotex began installing tanks, heat exchangers, boilers, and other equipment at the Willmar site, about 75 k ilometres nor theast of Estevan. “The capital equipment is

“Producers want to reduce the pressure on the surface watershed,” the Rotex president says. “Water from our plant site can be delivered fully heated to the fracturing job site. Even partially heated water will reduce their operating cost. If customers buy fracturing water from us, using the same facility for subsequent disposal of this water is a nat-ural fit. In future, we’re looking at the

"Right now, a landowner can get revenue for water from his dugout, although there is no guarantee of quality, consistency, temperature, or sufficient volume.”

–Kevin Baumann, Rotex Energy Ltd.

valued at more than $5 million,” he says.

Local workers have been employed as much as possible. Eight to 10 employees will run the Willmar operation 24 hours a day, 7 days a week.

possibility of recycling produced water at Willmar, which would be another reason for producers to use the facility.”

Baumann is oilpatch born and bred.

The son of an Alberta-based drilling

consultant, the Rotex founder got his start in business with a tank truck. Over the past 15 years, he’s developed and profitably sold several disposal facilities, and gone broke once. “I’ve learned what to do—and what not to do,” the Red Deer resident says with a grin. “No matter how smart your strategy may be, the right people are always the most important factor in a company’s success.”

Regarding the future for Rotex in this market, Baumann says that there is def-initely room for a new company such as Rotex who strives for generating their revenue from focusing on services such as disposal, waste processing, and source water supply, while offering an oil repay program to their customers to acknowledge that it is the customer’s oil that is entrained in the waste streams delivered.

OIL & GAS INQUIRER • February 2010

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British Columbia

B.C. government’s incentives will boost field activity in 2010

Photo: Mostar Directional Technologies Inc.

by Richard Macedo

B.C. Energy Minister Blair Lekstrom says industry budgets have been boosted by government incentives.

Capital expenditures and drilling will rise in British Columbia in 2010 as a result of a stimulus package put in place during the summer, according to a recent survey of 11 producers.

The Ministry of Energy, Mines and Petroleum Resources released the findings on Dec. 17.

Estimated 2010 capital investment for the producers was $1.52 billion before the stimulus was in place, but the government survey found that the government’s measures encouraged the producers to boost their expected 2010 investment by $600 million to $2.1 billion.

PricewaterhouseCoopers validated the survey methodology. Eleven of 14 companies responded to the survey, which was conducted between Oct. 14 and Nov 2. Capital investment for the 11 producers surveyed was $2.61 billion in 2008. Investment dropped to an estimated $1.86 billion in 2009 because of low natural gas prices and demand.

The survey also found that estimated 2010 drilling for the group was 183 wells

before the stimulus, while the measures encouraged them to boost wells spudded this year by 105 for a total of 288.

The stimulus package includes four royalty and two regulatory initiatives designed to further bolster British Columbia’s competitive business climate. A short-term royalty measure to help boost drilling in a time of sluggish natural gas prices includes a one-year, two per cent royalty rate for all wells drilled in a 10-month window.

Other royalty initiatives in the package included: • a n increase of 15 per cent in the existing royalty deductions for natural gas deep drilling.

• qualification of horizontal wells drilled between 1,900 and 2,300 metres into the deep royalty credit program.

• an additional $50-million allocation for the infrastructure royalty credit program to be offered this fall to stimulate investment in oil and gas roads and pipelines.

David Pryce, VP of operations with the Canadian Association of Petroleum Producers, said the survey’s results paint an accurate picture. “We worked with the department of energy there on some of the opportunities,” he said. “I think there was an expectation created in the dialogue, which helped industry start to think about what it might want to be doing in 2010, and they delivered.”

With the Horn River being at a nascent stage of development and interest in the Montney continuing to be heavy, producers will likely combine the fiscal package with the new opportunities to be in a strong position coming off the low gas price cycle and economic downturn.

“The fiscal package says B.C. wants us there,” Pryce said. “Getting something that helps, not just retain the producers, but retains the service sector [is also important]. The risk of losing the service sector south of border, I think, would be problematic as we come out of the downturn. It would defer any activity.”

The province also held its final land sale of 2009 on Dec. 16, producing its third-best calendar year in history despite depressed natural gas prices and lower demand. In the Dec. 16 sale, six drilling licences in the Horn River Basin delivered $121.4 million for British Columbia, which generated $172.3 million in bonus bids on 48,280 hectares.

This brought the year-end total to $892.9 million on 389,664 hectares, for an average of $2,291 per hectare. In 2008, $2.66 billion was spent to acquire 756,752 hectares at an average of $3,518 per hectare.

The December sale also closed a strong decade of auction revenue that climbed dramatically. From 1990–1999, British Columbia averaged $132.9 million in bonus bids while that average rose in the 10-year period from 2000–2009 to $762.2 million.

— DAILY OIL BULLETIN

BRITISH COLUMBIA WELL ACTIVITY DEC/08 DEC/09

WELL LICENCES

182

115

DEC/08 DEC/09

▼

WELLS SPUDDED

72

42

DEC/08 DEC/09

▼

WELLS DRILLED

74

40

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • February 2010

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Northwestern Alberta/Foothills

Alberta’s $384M auction more than doubles its land revenue for 2009

Photo: Concord Well Servicing

by Richard Macedo

A strong Alberta land sale in December raised hopes that the service sector will be busier this year.

In one fell swoop, the Alberta government’s revenue from its final land auction of 2009 more than doubled the province’s aggregate land revenue for the calendar year. The province took in $384.3 million in bonus bids on 194,378 hectares ($1,977 per hectare). Both the average price and the amount of land sold were the highest of the year.

The land sale on Dec. 16 brought Alberta’s year-end total to $741.7 million (average of $402.63) for 1.84 million hectares. The bonus total is the lowest since 2002, when A lberta attracted $501.5 million. In 2008, sales of oil and gas mineral rights raised $1.2 billion with 3.68 million hectares sold at an average of $333.58 per hectare.

“Industry had told us that if we were going to extend the incentive programs, we should make that announcement before the autumn to ensure we could positively affect budgets for the winter drilling season,”

commented Bob McManus, a government spokesman. “We made that announcement in June to have the greatest impact on investment decisions.”

Most interest was shown in northcentral areas, where producers have been extending plays with horizontal drilling and multi-stage fractures. Recent success has come through horizontal drilling in areas that are known to contain hydrocarbons but had previously been difficult to draw out or marginal using verticals.

Nine licences between 55-18W5 and 59-20W5 attracted most of the dollars, drawing about $323 million. “The larger blocks were in Edson, Sundance, Pine Creek, Fir; areas where companies have been applying both vertical and horizontal fracs,” said Chris Theal, managing director of oil and gas research with Macquarie Capital Markets Canada. “Most interest looks to be below and including the Bluesky, Gething,

Nikanassin, Doig, and Montney. I don’t think it has anything to do with the gas cycle.”

Canadian Coastal Resources Ltd. produced the land sale high, plunking down $46.8 million for an 8,192-hectare licence ($5,709 per hectare, also a land sale high).

The broker scooped up several sections at 58-22W5, 57-23W5, 58-23W5, and 58-24W5 for petroleum and natural gas below the base of the Bluesky-Bullhead and below the base of the Fernie group.

Windfall Resources Ltd. paid $43.6 million (5,322 per hectare) for an adjacent 8,192-hectare licence. The company picked up several sections at 57-21W5, 57-22W5, and 58-22W5. The area has been heavily drilled by industry. Daily Oil Bulletin records show that to the east of these parcels, NAL Oil & Gas Trust spud a well on Dec. 4 in the Pine Creek area targeting oil in the Cardium formation at surface location 1-33-57-20W5.

Celtic Exploration Ltd. has been busy in the Kaybob area. The junior producer has a standing gas well at Kaybob at surface location 13-4-59-18W5 that was spudded on Nov. 17, with the Notikewin member as the projected zone. The producer was active in the Dec. 16 sale, paying $1.6 million for a 7,936-hectare licence at 58-21W5. Celtic also acquired a lease parcel for $170,664 at 60-20W5.

“It supports the contention of many in the industry that when Alberta prospects are competitive, the government will see the rewards in land sales as part of their overall royalty/fiscal compensation structure,” said Gary Leach, executive director of the Small Explorers and Producers Association of Canada.

Oilsands parcels attracted $443,387 for 10,240 hectares. This brought the year-end total to $9.9 million for 101,449 hectares, compared to $288 million in bids received last year on 1.66 million hectares.

— DAILY OIL BULLETIN

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY DEC/08 DEC/09

WELL LICENCES

257

329

DEC/08 DEC/09

▲

WELLS SPUDDED

210

282

DEC/08 DEC/09

▲

WELLS DRILLED

219

263

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • February 2010

27

Northwestern Alberta/Foothills

Montney formation attracts Galleon and Birchcliff Several exploration and production companies plan to be busy in the Montney formation in Alberta and British Columbia this winter, they told the Small Explorers and Producers of Canada (SEPAC) investment forum on Nov. 30 in Calgary.

Galleon Energy Inc.’s accomplishments this year—advancing Montney resource projects, developing a new light oil resource project, reducing its cost structure, and improving its balance sheet— have set it up for growth in 2010 and beyond, said Steve Sugianto, president.

Galleon has about 540 drilling locations expected to keep it busy for the next eight years, said Sugianto. The $778million development drilling inventory, intended to unlock Eastern Montney gas,

resource at 1.3 trillion cubic feet, according to Galleon.

The company is also excited about its exploration project on the Puskwa, said Sugianto. It has identified a new highimpact light oil exploration project that will see drilling in 2010, the meeting heard. Currently balanced with 47 per cent oil and 53 per cent natural gas based on reserves, Galleon plans to be weighted 60-40 next year as in the past few weeks its oil projects “are coming on strong,” said Sugianto.

Based on a database of 32 producing horizontal wells in the east Montney, Galleon anticipates favourable pro­ ject economics: all-in costs of $1.3 million per well, first-year production of

Photo: Galleon Energy Inc.

"When the company first started drilling this project, it took 12 days to drill a well at a cost of $800,000. In the past 18 months, costs have fallen to about $550,000 and drilling times have shortened to eight days."

– Steve Sugianto, President, Galleon Energy Inc.

Galleon says it has an eight-year drilling inventory.

Puskwa oil, and Doig oil, consists of 400 horizontal wells in the Eastern Montney ($520 million), 40 oil wells in the Puskwa ($88 million), and 100 oil wells in the Doig ($170 million).

Galleon believes the Eastern Montney represents a large resource potential with large upside value. It has low operating costs at $0.93 per thousand cubic feet (Mcf) equivalent or $5.87 per barrel of oil equivalent (boe) and high-netback gas with liquid-rich content—natural gas liquids with a recovery of more than 20 barrels per million cubic feet (MMcf).

Production life is expected to exceed 10 years based on original analog pools. Its best-case independent evaluation pegs the 28

February 2010 • OIL & GAS INQUIRER

710 Mcf per day per well, reserves of 1.8 billion cubic feet of gas, 27,000 barrels of oil reserves, and a payout period of 1.4 years. These assumptions are based on a gas price of $5.50 per Mcf and oil price of $75 per barrel.

“Drilling costs are expected to continue to decrease,” said Sugianto. “When the company first started drilling this project, it took 12 days to drill a well at a cost of $800,000. In the past 18 months, costs have fallen to about $550,000 and drilling times have shortened to eight days,” he said.

Currently producing more than 3,000 boe per day net, Galleon plans to expand exploration and production at its Central Montney Project #1 to 4,000 boe per

day this year. Sugianto told the SEPAC meeting that the project has low operating costs of less than 52 cents per Mcf or $3.09 per boe and high-netback gas with liquids-rich content. It also features a 100 per cent owned and operated 28 MMcf per day gas plant.

The economics at Galleon’s Doig oil resource project are comparable to those of the Bakken and the Cardium, he said.

According to Galleon, wells cost $1.7 million, first year oil production is 46 to 90 barrels per day, gas output is 67 MMcf to 135 MMcf per day, and the payout period is 1.1 to 2.1 years.

The company has 22 sections (70 per cent working interest) of land on the resource, whose oil is 39 degrees API and 40 existing vertical wells encountered the pay zone. Four horizontal wells have been drilled to date; the first well, with a 400metre lateral, has produced more than 17,000 boe in 10 months and current volumes are 50 boe per day.

Sugianto said he was encouraged by a recent horizontal well with a 900-metre lateral that has been producing at an average rate of about 161 boe per day in two months. The company plans to drill about 20 horizontal wells in this area in 2010.

Birchcliff Energy Ltd. is also active in the area with 28 wells drilled to date, said Myles Bosman, VP of exploration and COO. It plans to drill seven gross (4.9 net) horizontal gas wells in the Montney/Doig in the 2009–2010 season.

Its preliminary budget of $28 million for 2010 includes $12 million for the Pouce Coupe south gas plant and $16 million on horizontal wells. To keep the plant full, it will drill three to four wells in 2010 and two to three wells in 2011 and 2012, the meeting heard.

Each horizontal well costs about $5 million to drill, case, complete, and tie in.

The company expects ultimate recovery of six billion cubic feet per well. The 30 MMcf per day gas plant, expected to cost $47.5 million, is on schedule and on budget for an April 2010 start, said Bosman. “We’ve already initiated our Phase 2 of the plant, which could see a further 30 [MMcf] per day expansion, its potential to occur in the fourth quarter. The funding of that is being considered as part of our 2010 budget planning,” he said.

— DAILY OIL BULLETIN

Northwestern Alberta/Foothills

ARC acquires $180M in assets, mostly at Ante Creek recently initiated successful horizontal drilling program.”

The assets being acquired currently produce approximately 2,000 boe per day, split 25 per cent liquids and 75 per cent natural gas. ARC expects 2010 production from these assets will average 2,500 boe per day.

ARC estimates that 7 MMboe of proved reserves and 12.6 MMboe of proved-plusprobable reserves are being acquired through this transaction. Included in the acquisition are 30.5 sections of developed land and 163.5 sections of undeveloped land. This will be a 20 per cent increase in ARC’s undeveloped land base.

In the Ante Creek area alone, the acquisition adds 95 sections (60,100 acres) of

Photo: ARC Energy Trust

ARC Energy Trust has agreed to pay $180 million in cash for a general partnership that holds oil and gas assets in Ante Creek and other areas of northern Alberta.

The acquisition will increase ARC’s current production by approximately 2,000 barrels of oil equivalent (boe) per day and its undeveloped land holdings by approximately 20 per cent while adding an estimated 12.6 million barrels of oil equivalent (MMboe) of proved-plusprobable reserves. “ T h i s ac qu i s it ion s ig n i f ic a nt ly increases our land position in the Ante Creek region, which is a key growth area for us. Ante Creek is a tight Montney oil and gas property where we have grown production from 1,500 boe per day in

“This acquisition provides effective control of the known play in the area and will allow us to expand our recently initiated successful horizontal drilling program.”

John Dielwart, CEO, ARC Energy Trust

2000 to over 5,000 boe per day today through the drilling of over 125 successful wells and property consolidation,” said John Dielwart, ARC’s CEO. “At Ante Creek, we have proven that we can add significant value through t he appl ic at ion of tec h nolog y,” he added. “This acquisition provides effective control of the known play in the area and will allow us to expand our

land, increasing ARC’s total land holdings in the area by 70 per cent to 232 sections (148,500 acres). Included in the acquisition is the remaining 30 per cent working interest in an ARC operated gas plant at Ante Creek, taking the trust’s ownership of the plant to 100 per cent.

T he acquisition price work s out to $25.71 per proved boe and $14.30 per proved-plus-probable boe prior to

attributing value for the gas plant and the undeveloped land. Including future development capital, the acquisition price is $36.89 per proved boe and $20.50 per proved-plus-probable boe.

ARC said it has identified at least 30 horizontal drilling opportunities on the acquired properties with the potential for much greater development. The trust has added $35 million to its 2010 capital budget, resulting in a revised budget of $610 million.

To date, ARC has drilled six horizontal wells in the Ante Creek field that have been completed using multi-stage fracturing technology. The two ARC horizontal wells with the longest production history averaged approximately 500 boe per day in the first 30 days of production and are still producing almost 250 boe per day after 11 months of production. The other four wells have only recently been put on production and are performing as expected.

The acquired properties include a recent horizontal well that has averaged over 600 BOE per day of production during its first 30 days. ARC’s independent reserve evaluators have estimated that the ultimate recovery from these horizontal wells is expected to average over 300,000 boe. Including the 30 locations identified on the new lands, ARC believes it has approximately 75 horizontal drilling locations on its lands in Ante Creek.

Outside of Ante Creek, but still in the northern Alberta region, production of approximately 800 boe a day will be acquired along with 14 developed sections (9,000 acres) and 85 undeveloped sections (54,000 acres). These minor properties are a significant addition to ARC’s undeveloped land base in the area.

ARC now expects to spend approximately $70 million in the Ante Creek area in 2010 and drill 2 vertical wells and 14 horizontal wells. It expects to exit 2010 with production of approximately 7,500 boe per day from the Ante Creek properties, an increase of 42 per cent from production of 5,300 boe per day prior to the acquisition. A portion of the 2010 capital will be spent on expanding ARC’s existing processing and treating facilities to handle the new volumes, hence a large portion of the growth is not expected to be on stream until the fourth quarter.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • February 2010

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Northeastern Alberta

Laricina Energy pushes ahead with its Saleski carbonate project

Photo: Laricina Energy Ltd.

by Lynda Harrison

Two horizontal well pairs are scheduled for drilling this winter prior to a 2010 pilot start-up.

Laricina Energy Ltd. intends to be the first to use horizontal drilling, steam assisted gravity drainage (SAGD), and solvents in Alberta’s carbonates, and having received regulatory approval in July for its 1,800 barrel per day Saleski project, its next step is to achieve commerciality. The company is also considering going public.

In its four-year existence Laricina has prospected, tested its resource, raised $500 million, and now people want to see oil in the tank because there’s nothing quite as impatient as investors, said Glen Schmidt, its president and CEO. “Ideas are interesting; results are everything,” he said in mid-December.

Laricina holds more than 3.9 billion gross barrels (2.9 billion net) of potential resources between two projects: 60 per cent owned Saleski, where the 1,800 barrel per day pilot is under construction to recover bitumen from the Grosmont formation,

and 96 per cent owned Germain, recovering bitumen from the Grand Rapids and Winterburn formations.

Both projects are about 100 to 130 kilometres southwest of Fort McMurray.

Combined, they represent one of the largest in situ oilsands platforms in the industry.

The use of a SAGD-based recovery scheme at Saleski will be a first for the carbonates. “This will be a significant development for Laricina and will advance recognition of the Grosmont formation as the second-largest in situ development opportunity in Alberta,” said Schmidt.

The company has followed up the recently received approval for the pilot project with an amendment to add solvents to reduce the amount of steam needed. This second phase to add solvents is slated for 2012. Development is scheduled to occur in phases of 20,000 to 60,000 barrels of oil per day at Saleski, to reach ultimate gross production of 270,000 barrels per day over an estimated 25 years of reserve life.

At Germain, Laricina’s second core area, regulatory approval for an 1,800 barrel per day SAGD pilot was received last October. In November, the company submitted an amendment to increase the initial project to 5,000 barrels per day and incorporate a solvent assisted recovery process known as solvent-cyclic SAGD (SC-SAGD patent pending).

Regulatory approval for the amendment is anticipated in the third quarter of 2010 with construction starting in 2011 for start-up in the second half of 2012.

The use of a SAGD-based recovery scheme at Saleski will be a first for the carbonates.

Two horizontal well pairs are to be drilled at Saleski this winter in preparation for a 2010 pilot start-up. “We’ll be driving piles into the ground in February and placing equipment at the end of the first and second quarter and connecting all the equipment together for start-up in the fourth quarter of 2010,” Schmidt said.

Commercial expansion to 20,000 barrels of oil per day is slated for start-up in 2015, eventually rising to 180,000 barrels per day in staged developments over the next 10 years. The area contains more than 1.6 billion barrels of gross recoverable bitumen.

Plans are to drill four vertical observation wells at Germain this winter.

DEC/08 DEC/09

DEC/08 DEC/09

NORTHEASTERN ALBERTA WELL ACTIVITY DEC/08 DEC/09

WELL LICENCES

176

158

▼

WELLS SPUDDED

46

50

▲

WELLS DRILLED

52

62

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • February 2010

31

Northeastern Alberta “Once we receive t he a mend ment approval, we hope to begin ordering equipment at the end of 2010, but we will be doing detailed engineering throughout 2010,” Schmidt said.

Over the next 12 months, Laricina (the Latin word for larch tree) plans to build an all-weather road to Saleski, drill the horizontal wells, complete construction of the Saleski pilot, add to its operations team, continue the regulatory process, and receive approval for both the Saleski Stage 2 solvent addition and Germain’s 5,000 barrels of oil per day amendment.

In addition, the company intends to start detailed engineering for Germain.

It also plans to advance a development strategy next year for its other properties, at nearby Burnt Lakes, Poplar Creek, and Conn Creek, as well as update its total company resource estimate, which is currently 4.1 billion barrels of net recoverable resource.

The world economic slowdown that started in 2008 put the projects behind by a year, said Schmidt. Had capital markets maintained their level, Saleski would be coming on stream right now, he said. “We were moving relatively briskly through the fall of 2008 and when the economic cycle paused, we paused.”

Amid signs of economic recover y, t he compa ny recent ly ra ised $83.4

million in common equity primarily for Saleski and it needs another roughly $250 million for Germain. In 2010 it will seriously consider going public to raise that amount, Schmidt told the Daily Oil Bulletin from his downtown Calgary office.

Laricina plans to spend 75 per cent of its 2010 capital budget of $73.5 million on demonstrating SAGD in the carbonates at Saleski and the rest on advancing engineering at Germain and application studies and lab testing. It has a working capital forecast at the end of the year of about $50 million.

— DAILY OIL BULLETIN

Opti Canada plans $120M capital program in 2010

32

February 2010 • OIL & GAS INQUIRER

with the reservoir responding to increasing and consistent steam volumes and the upgrader fully operational and approaching design yields.”

Progress continues to be made in the ramp-up of the project. Currently, steam injection is approximately 100,000 barrels per day with bitumen production of approximately 17,000 barrels per day. Average bitumen production for the month of November was approximately 15,200 barrels per day.

After the turnaround in the third quarter, the number of well pairs receiving steam has increased to over 70, with 50 well pairs on production as of Dec. 7, 2009.

Upgrader on-stream time is increasing and, in November, improved reliability allowed the project to process 95 per cent of produced and purchased bitumen. The solvent deasphalter and thermal cracking units are now in operation, allowing the upgrader to transition from gasifying vacuum residue to gasifying asphaltenes. As a result, proprietary Premium Sweet Crude yields have increased to approximately 70 per cent.

Once this transition is complete, Opti expect those yields to reach approximately 80 per cent.

Photo: Joey Podlubny

Opti Canada Inc.’s board of directors has approved a $120-million capital program for 2010. The company’s share of budgeted costs for Phase 1 of the Long Lake Project in 2010 is expected to be approximately $92 million.

Completion of the ash processing unit in the upgrader has been deferred to 2011 in order to manage 2010 capital costs.

Phase 1 expenditures will be primarily directed towards sustaining capital for the steam assisted gravity drainage (SAGD) operation and other initiatives to ensure the long-term reliability of the project, including the installation of electric submersible pumps and the drilling of two new well pads. The company said it continues to estimate an average of $8 to $9 per barrels of sustaining capital over the life of the project.

In 2010, Opti will invest approximately $23 million in advancing Phase 2 engineering and detailed execution plans with $5 million budgeted for development of Phases 3 through 6. Opti and its jointventure partner, Nexen Inc., have agreed to defer the sanctioning of Phase 2 to late 2011 in order to gain additional Phase 1 operating experience prior to construction of future phases, as well as to potentially obtain greater clarity on CO2 regulations.

“At the Long Lake Project, plant reliability and performance have improved substantially since the turnaround in September,” said Chris Slubicki, president and CEO of Opti. “While it is early in the ramp-up process, we look forward to a significant ramp-up through 2010

Opti says Long Lake’s performance has improved since last fall.

— DAILY OIL BULLETIN

Northeastern Alberta

Sunshine’s carbonates pilot project achieves its first step forward which will be applied to modelling of future development plans with more confidence.

Four core holes were dr i l led i n Harper during the winter of 2008–2009 and another 38 core holes (with 20 more contingent locations) are planned for

The pilot project will include one steam cycle consisting of an injection, soak, and production period. Evaluation of pilot project results will determine t he f ut ure development plan. A f ter steam injection, the well will be shut in for a one- to two-day soak, followed by

Photo: Sunshine Oilsands Ltd.

An applicaton from Sunshine Oilsands Ltd. for an in situ pilot carbonate oil program has been approved by the Energy Resources Conservation Board (ERCB). The private company had requested scheme approval to conduct a single-well cyclical steam stimulation (CSS) pilot that will be under 1,000 barrels per day at 11-21-95-24W4 in the Harper area of Alberta.

The proposed pilot site is located in the Athabasca oilsands region, 42 kilometres southwest of Chipewyan Lake in an area with winter-only access. The development proposal calls for 2,000 barrels of oil per day from a commercial steam assisted gravity drainage (SAGD) phase on stream in 2014, followed by two 20,000 barrels of oil per day phases, to come on stream in 2017 and 2020, respectively.

The pilot will allow the Calgary-based company to analyze the bitumen and determine the correct approach for carbonate development—such as simulations of CSS versus SAGD, and horizontal versus vertical wells. Sunshine has a 100 per cent working interest in over 600 sections of land in the Harper area.

Its initial development plans include a conventional heavy oil project and a 180,000 barrel per day production profile from part of its Cretaceous land inventory.

Sunshine’s initial adjudicated resource report, which was based on 58 core holes encompassing 396 sections, attributed 9.1 billion barrels of original bitumen in place with 1.3 billion best-case gross lease recoverable resources.

The project will test the application of a thermal recovery process that is expected to improve the feasibility of heavy oil recoveries from the Grosmont formation in Sunshine’s lands this winter and next winter. The injection cycle next winter would be performed pending the results of the cycle proposed for this winter.

Sunshine is proposing that steam be injected into the Grosmont formation through a new well at 11-21-09524W4. Steam will be generated using a portable 25 million British thermal unit steam generator equipped with source water-sof tening facilities. Once t he pilot data are available, Sunshine plans to repeat the simulation work with histor y matching and model validation,

Sunshine’s Harper project sits in a winter-accessible remote site.

The development proposal calls for 2,000 barrels of oil per day from a commercial steam assisted gravity drainage (SAGD) phase on stream in 2014.

this winter. This core-hole program will allow the company to define the carbonate resource and further characterize the reservoir.

Water to generate steam will be supplied from Zigzag Lake. Additional potential water sources will be Burnt Lake (16 -23-95-25W4), Little Island L a k e ( N -2 4 - 9 5 -2 5 W4 ), a n d t w o unnamed lakes at 7-17-96-24W4 and 1-10-95-23W4.

the production period, which will last for a few weeks until the equipment has to be removed.

T he company has identified the Bigstone Cree Nation, Alberta Pacific Forest Industries, Alberta Sustainable Resource Development, A lber ta Environment, the ERCB, and a trapper named Randall Noskiye as stakeholders and is in consultation with them.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • February 2010

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Central Alberta

Photo: Government of Alberta

Quebec and Ontario dump on Alberta’s oilsands but take the money

Premier Ed Stelmach has recently received unusually warm media coverage in Quebec over oilsands issues.

Ganging up on Alberta’s oilsands is becoming a national sport and the badgering was on full display at the global climate conference in Copenhagen during December. But what would the country’s economy look like if the cash flow pumped from the oilsands was suddenly turned off?

With climate change now morphing into a national-unity issue, angry defenders of western oil argue that the provinces doing most of the environmental fingerpointing—namely, Ontario and Quebec— can only afford their own social programs and tax rates thanks to the tarry cash cow they love to disparage.

Alberta’s premier says his province’s oil-rich economy provides the rest of the country with about $21 billion. By way of comparison, that’s more than all of Canada’s $18-billion defence budget and about half of what Ontario spends on health care.

Oilsands economic activity is a key driving force behind the federal equalization program, which transfers more than $8 billion a year to Quebec. “The costs to [other] provinces might be a lot larger than they imagine,” warns Robert Mansell, an economist from the University of Calgary, suggesting that Canada’s havenot provinces have a lot at stake on bitumen development in northern Alberta.

Six provinces are set to receive about $14.2 billion in equalization payments this year. For 2009, the formula will funnel about $8.4 billion to Quebec, $2.1 billion to Manitoba, $1.7 billion to New Brunswick, $1.6 billion to Nova Scotia, $347 million to Ontario, and $340 million to Prince Edward Island.

Despite Alberta’s financial support, Quebec and Ontario took public shots at the province’s oilsands development during the Copenhagen climate summit.

Both Quebec Premier Jean Charest and Ontario Environment Minister John Gerretsen refuse to let their provinces carry the load for bigger polluters, like Alberta and Saskatchewan, when it comes to meeting emissions goals. “If they [the oilsands] are developed, there may have to be larger greenhouse gas emission [cuts] elsewhere in the country in order to meet our overall targets,” Gerretsen said.

Alberta Premier Ed Stelmach shot back in a public letter and television interview after the Copenhagen conference.

“Perhaps the most frustrating part of this all was the finger-pointing by Quebec and Ontario,” Stelmach told CTV Edmonton.

“If this leads to really killing Alberta’s economy, who is going to support the programs in other provinces?”

Stelmach said Albertans spend more than $21 billion annually in financing the other provinces. Alberta’s position received some sympathetic news coverage in Quebec, a province whose hydroelectr ic development potential has prompted Canada’s most aggressive support for tough climate-change targets.

“Hypocrisy has a name, or rather two: Quebec and Ontario,” wrote columnist Lysiane Gagnon in Montreal’s La Presse. “In short, it’s thanks to the oilsands that allows Quebec to live beyond its means and offer luxury services such as $7 [-a-day] daycares and universities that are practically free.”

In 2006, Mansell calculated that Quebec was a net beneficiary of $217.1 billion (in 2004 dollars) from the equalization program between 1961 and 2002.

That has represented $767 per year for every Quebec man, woman, and child, he said. Over the same period, Alberta paid out $243.6 billion and Ontario paid $314.5 billion, he said. That has cost $2,510 for every Alberta resident every year, and $758 for every Ontarian.

— CANADIAN PRESS

CENTRAL ALBERTA WELL ACTIVITY DEC/08 DEC/09

WELL LICENCES

202

293

DEC/08 DEC/09

▲

WELLS SPUDDED

216

186

DEC/08 DEC/09

▼

WELLS DRILLED

231

199

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • February 2010

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Southern Alberta

Photo: Eveready Energy Services

Q3 service sector revenue improves over Q2 but falls $1.8B from 2008

Some analysts expect 2010 to be a recovery year for Canada’s service and supply sector.

Although better than the dismal second quarter, third-quarter service and supply company revenues were down $1.8 billion from a year earlier, with only 2 out of 46 reporting companies showing higher revenues than last year.

Cash flow slumped to $530 million, off $461 million from a year earlier with only five companies—Pembina Pipeline Income Fund, Keyera Facilities Income Fund, Divestco Inc., Destiny Resource Services Corp., and Blackwatch Energy Services Corp.—reporting an improvement from last year.

With the struggle to maintain cash flows, most service companies slashed their capital budgets this year, although the overall total for the 46 companies at $883 million for the three months ended Sept. 30, 2009 was down only $163 million from last year. That was due to Inter Pipeline Fund, which has several pipeline

expansions underway and spent $420.6 million in the quarter, up $265 million from last year.

Excluding Inter Pipeline, the remaining 45 service and supply firms cut capital spending almost in half to $462 million, with Mullen Group Ltd. and Ensign Energy Services Inc. showing the severest declines.

Capital spending for the first three quarters of 2009 fell by more than $1 billion to $2.58 billion, which was nearly 50 per cent below capital spending in 2007 when the Canadian oilpatch was still drilling many wells. Part of the reason for the lower expenditures this year was a drop in acquisition spending, which declined to $396 million from $949 million in 2008.

Profitability for the three months ended Sept. 30 improved from the second quarter when the sector barely avoided a net loss as a group. The 46 reporting companies showed a combined profit of $203.8 million, down

$163 million from 2008. The decline would have been more severe were it not for a turnaround by Flint Energy Services Ltd., which managed a profit of almost $10 million versus a $163 million net loss in 2008 earlier, when it booked a $190-million impairment charge against its assets.

Nine month profits declined by $431 million from 2008 to $842 million and the slump would have been even larger were it not for a $165-million year-over-year profit change at Flint Energy. Cash flow declined by 27 per cent to $1.94 billion, with only six companies reporting higher cash flow for the first three quarters of 2009. They were: Keyera Facilities Income Fund, Pembina Pipeline Income Fund, Xtreme Coil Drilling Corp., Leader Energy Services Ltd., Destiny Resource Services, and Blackwatch Energy.

Some analysts expect 2010 to be a recovery year for Canada’s service and supply sector, although activity levels will be nowhere close to the peak levels experienced in 2005 and 2006. Many producers have raised their capital spending plans for 2010 and the industry expects natural gas prices, on average, to be higher than this year.

FirstEnergy Capital issued a report predicting 13,900 wells will be drilled in Canada this year, up from an expected 9,111 wells last year. Oil-related drilling is expected to rise for the next two years and gas-related drilling is expected to climb to 7,263 in 2010 and 8,502 wells in 2011, which is still only half the peak level experienced in 2005.

Although drilling will recover, it won’t rise enough to return pricing power to the service sector, and rates charged to producers are expected to stay flat.

FirstEnergy also forecast that more than $3.5 billion in producer cash flows will be removed simply by the sharp reduction in natural gas production.

— DAILY OIL BULLETIN

SOUTHERN ALBERTA WELL ACTIVITY DEC/08 DEC/09

WELL LICENCES

448

284

DEC/08 DEC/09

▼

WELLS SPUDDED

427

225

DEC/08 DEC/09

▼

WELLS DRILLED

446

230

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • February 2010

37

Southern Alberta

Photo: Joey Podlubny

Precision plans to cut capital spending and decommission 38 drilling rigs

Precision has earmarked $25 million in 2010 to outfit some rigs for unconventional gas drilling.

Although it will upgrade some of its drilling rig fleet to meet the changing demands of customers chasing unconventional resources, Precision Drilling Trust announced on Dec. 16 that it will reduce spending in 2010 and that its rig fleet will be downsized.

Capital expenditures for this year of about $75 million, including $50 million in sustaining upgrade and infrastructure expenditures, are based upon currently anticipated rig activity for 2010. In addition, Precision has earmarked $25 million for performance improvements to certain rigs to align with potential customer opportunities in unconventional resource plays in Canada and the United States.

The planned $75-million capital budget for 2010 pales in comparison to 38

February 2010 • OIL & GAS INQUIRER

the $179.44 million the trust spent during the nine months ended Sept. 30, 2009. Its capital budget for 2009 is $210 million.

The trust said planned 2010 expenditures will move 10 rigs from Precision’s Tier 2 c la ssi f icat ion up to Tier 1 (Precision’s Super Series) and will move three to five rigs from Tier 3 to Tier 2, which are the trust’s high-performance rigs capable of drilling both directionally and horizontally. There are currently no plans to build new rigs.

Precision also said its board of trustees is continuing the “indefinite suspension of cash distributions” in order to maintain focus on debt reduction, and there will not be a special year-end distribution.

In an effort to cull its herd of Tier 3 rigs, Precision said it will decommission 38 drilling rigs, of which 26 are part of

the Canadian fleet and 12 are part of the U.S. fleet. All of these rigs are Tier 3 rigs.

Certain component parts of these decommissioned rigs will be used in the trust’s ongoing operations.

“The combination of upgrading 13 to 15 of our existing drilling rigs and permanently decommissioning 38 of our least efficient, least profitable Tier 3 rigs significantly high-grades the Precision fleet,” president and CEO Kevin Neveu said in a statement.

The move will allow Precision to exit 2010 with over 72 per cent of its fleet as Tier 1, Super Series, and Tier 2, which are horizontally capable, high-performance rigs. It’s a scenario Neveu says puts the trust in a good position once customer demand improves.

“This repositioning of the Precision fleet supports our strategy of providing high-performance, high-value services for the rapidly changing demands of our customers pursing unconventional oil and gas reserves in our core markets,” he said. “We remain poised to further upgrade Tier 3 rigs or consider new build opportunities when customer demand and contract economics fully support additional investment.”

In addition to the 38 drilling rigs that will be retired, 30 service rigs and 9 snubbing units will also be decommissioned. As a result the decommissionings, Precision said it will take a non-cash, pretax charge to earnings in the range of $80 million to $90 million for the fourth quarter of 2009.

Once the decommissioning process is complete, Precision’s rig fleet will stand at 352 rigs, all of which are marketable and can return to work in a short period of time without additional capital. With the recent movement of three rigs to Canada from the United States, the trust currently has 203 rigs in Canada, 146 rigs in the United States, and 3 internationally.

Precision’s board continues to evaluate and plan for the conversion from a trust to a more traditional corporate structure.

These plans are ongoing, and it is anticipated that this conversion will take place well ahead of new Canadian tax measures for trusts slated for Jan. 1, 2011.

— DAILY OIL BULLETIN

Southern Alberta

Newalta budgets $87M for capital expenditures in 2010 Waste management company Newalta Inc. announced on Dec. 7 that it has budgeted $87 million for capital expenditures in 2010.

Newalta will pay for the spending with funds from operations, with 40 per cent of the total expected to be spent in the first half of next year. The Calgarybased company said its growth capital expenditures of about $60 million will allocate $35 million to Onsite Services to support recent growth in Newalta’s heavy oil business unit.

Meanwhile, $20 million will be divided equally between facilities in eastern and western Canada, while the remaining $5 million in growth capital expenditures are for corporate investments. Maintenance capital expenditures are budgeted to be $27 million and include $9 million in the construction of additional landfill cells largely at the Stoney Creek Landfill near Hamilton.

The landfill has an estimated life of 10 years, and the 2010 expenditures will be used to construct an additional landfill cell to provide capacity for about two years.

Total Energy to buy oilfield services business operated by DC Energy the size of its rental equipment fleet by 80 per cent through the acquisition. It will also increase its heavy truck fleet by 27 per cent.

Total said its letter of agreement calls for it to buy 3,600 pieces of rental equipment, 20 heavy trucks, and 59 trailers and inventories. The only assets excluded from the deal are DC’s land and buildings. Total currently owns and operates approximately 4,500 pieces of rental equipment, 74 heavy trucks, and 131 trailers.

Of the purchase price, $32 million is to be paid in cash at closing, with $12.5 million to be paid through the issuance of convertible unsecured debentures of Total. The cash portion will be funded through bank debt.

Photo: Joey Podlubny

Total Energy Services Inc. says it has agreed to pay $44.5 million to buy the oilfield services, rental, and transportation business currently conducted by DC Energy Services Inc. of Calgary. DC Energy is a privately held company that operates business throughout western and northern Canada and Alaska through seven primary locations and several satellite locations and currently employs approximately 135 people.

Calgary-based Total said DC’s business assets are complementary to its existing equipment fleet. The company added that it will make offers of employment to “substantially all” of DC’s employees and increase

Total says DC Energy Services’ rental inventory complements its own fleet of equipment.

Average rig count for 2009 declines by 41 per cent from 2008 Alberta bore the brunt of a 41 per cent decline in drilling rig activity during 2009, which saw only 236 rigs at work, the fewest since 1992. Rig utilization peaked in the second week of January at 56 per cent and briefly touched 50 per cent in December. But the overall average—based on weekly surveys—was only 28 per cent.

The fleet of available drilling rigs in Canada declined for the second year in a row to 845 units, but the fall was not enough in a year that saw massive cutbacks in capital budgets by producers due to very weak gas prices and poor equity markets.

In Alberta, on average only 141 rigs were at work during 2009, down 47 per cent from 265 in 2008 and off 64 per cent from the 2005 peak year activity, which saw producers employ an average of 396 rigs in the province. This year’s employment rate was the lowest since 1992, when only 101 rigs were active.

Saskatchewan was the second-hardest hit province, with a 37 per cent decline to an average of 43 working rigs compared to a very busy 2008, when high oil prices and the Bakken boom pushed the rig count to 67 rigs. An average of 43 units at work in 2009 is the lowest since 2004.

B.C. producers kept 47 rigs working during 2009, a 27 per cent decline from 64 units in 2008. The peak year was 2005, when 74 rigs were at work in the province.

The western province with the smallest production, Manitoba, barely saw a downturn in 2009 as producers moved to exploit oil formations with horizontal drilling. An average of five rigs were kept busy in the province this year, down one from 2008.

In December, the Nickle’s Rig Locator found 337 rigs at work as activity started to wind down for the holiday season.

Comparing activity to prior year levels, December has been a relatively good month with well over 400 drilling units, which put activity levels down only 24 to 53 rigs from the same period in 2008.

From mid-June to early October 2009, the average rig count was down by over 200 rigs from 2008.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • February 2010

39

Southern Alberta

U.S. law firm sues Greg Noval and four others over Canadian Superior’s Trinidad play Four former senior executives of Canadian Superior Energy and the company’s current COO have been accused of misleading investors about a key offshore natural gas development in Trinidad and Tobago.

The class-action lawsuit was filed in a U.S. District Court in New York by Dyer & Berens LLP, a Denver-based law firm that focuses on investor class action suits involving financial fraud.

The lawsuit is on behalf of investors who bought Canadian Superior stock between Jan. 14, 2008, and Feb. 17, 2009, before the Calgary-based company restructured under creditor protection and installed a new board of directors.

The company itself is not named as a defendant. “Canadian Superior intends to take any necessary steps to protect its interests in this matter,” the company in a statement released on Dec. 14.

The suit named former CEO Craig McKenzie, former president and COO Michael Coolen, former executive chairman Greg Noval, former COO Leigh

Bilton, and current COO Leif Snethun as defendants.

“The individual defendants are liable as participants in a fraudulent scheme and course of conduct which operated as a fraud or deceit on purchases or Canadian Superior common stock by disseminating materially false and

that the discovered reserves for Intrepid block 5(c) were below the economic threshold for development.

The complaint also says Canadian Superior did not mention it had notified BG of its plan to begin a corporate sale in November 2008 so that it could deal with financial constraints that were

The five individual defendants are allegedly liable as participants in what the plantiffs call a "fraudulent scheme." misleading statements and/or concealing adverse facts,” the complaint alleges.

Many of the allegations, which have not been proven in court, centre around an offshore natural gas development in Trinidad and Tobago, which Canadian Superior had been jointly developing with Challenger Energy Corp. and U.K. firm BG Group. In August 2007, when Canadian Superior and Challenger announced the farm-in agreement with BG, the suit alleges the defendants failed to disclose

preventing it from meeting its financial obligations. Canadian Superior is also accused of failing to tell investors it had violated the terms of its joint operating agreement with BG and didn’t pay its drilling operator in a timely manner.

“As a result of the foregoing, defendants lacked a reasonable basis for their positive statements about the company, its prospects, and earnings growth,” the complaint says. The plaintiff is identified as David Sgalambro and “all others

LE B I X E BE FL O T l l a a S t t i s o Y n n i A . .

P . r I T e k s, quic e c i r p er Low

40

February 2010 • OIL & GAS INQUIRER

.

Southern Alberta similar situated.” While it’s not known how many investors the class action could involve, the “plaintiff believes that there are hundreds or thousands of members in the proposed class,” the complaint says.

Canadian Superior has faced a litany of issues in the past year. Last February, BG Group persuaded an Alberta judge to put Canadian Superior’s stake under the control of a receiver amid fears that final testing and completion of a well would not be completed, given Challenger’s and Canadian Superior’s financial problems.

A mont h later, Cha l lenger a nd Canadian Superior both filed for protection from creditors under the Companies’ Creditors Arrangement Act. In late April, Noval and Coolen were forced out by Canadian Superior’s board of directors.

Canadian Superior sold its 45 per cent stake in the Trinidad field for US$142.5 million to BG Group in May. In June, Canadian Superior agreed to merge with Challenger in a friendly deal worth $77.8 million. Canadian Superior now holds a 25 per cent interest in the Trinidad block.

— CANADIAN PRESS

Enerflex board of directors agrees to Toromont’s takeover offer Toromont Industries Ltd. and Enerflex Systems Income Fund have entered into a support agreement pursuant to which Toromont has agreed to increase its offer to acquire Enerflex to $14.25 per unit. The board of directors of Enerflex, upon the

of Enerflex units on Oct. 16, 2009. The maximum amount of cash to be paid by Toromont will be approximately $315.6 million and the maximum number of common shares of Toromont to be issued will be approximately 11.8 million.

Enerflex chairman John Aldred said the transaction will give the combined businesses the “scale and reach to be a highly effective and competitive global player.” recommendation of the special committee of independent directors, has unanimously agreed to support the offer.

Enerflex chairman John Aldred said the transaction will give the combined businesses the “scale and reach to be a highly effective and competitive global player.” The company plans to locate its headquarters in Calgary.

The revised offer represents a premium of 42 per cent to the closing price

“We are delighted to have achieved our objective of reaching a negotiated transaction with the board of Enerflex,” said Robert Ogilvie, chairman and CEO of Toromont. “The exceptional employees and management teams in both organizations provide the depth of personnel that will enable us to quickly achieve the global market presence that will make this combination successful.”

— DAILY OIL BULLETIN

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February 2010 • OIL & GAS INQUIRER

Saskatchewan

Photo: Brian Zinchuk, Pipeline News

Reliable Energy slowly advances its Bakken expansion program

Reliable has a Bakken oil play in Saskatchewan and a Devonian reef prospect in central Alberta.

Reliable Energy Ltd. continued to slowly expand its operations during the third quarter of 2009, focusing on its planned drilling and seismic programs on its Bakken play in the Kirkella area in southeastern Saskatchewan and southwestern Manitoba.

At the end of the third quarter, Reliable completed its development drilling program having drilled four (3.9 wells net) into its South Kirkella Bakken oil pool. Of the four wells, one is completed, fracture stimulated, and on production at 85 barrels (net) per day of oil.

Two wells were perforated and placed on production and have each averaged 37 barrels per day (net) of oil with no produced water. Reliable intends to fracture stimulate these two wells in the near future to maximize their potential.

The fourth well is currently undergoing fracture stimulation treatment and was expected to be on production in

December. Current production from the wells in the pool is approximately 200 barrels (net) per day of oil with overall corporate production at approximately 220 barrels of oil equivalent per day (net).

Based on the current level of development and exploratory drilling, the company expects to exit 2009 at 250 to 300 barrels of oil equivalent (boe) per day of production. The exploration program previously announced by the company is proceeding according to plan with four wells (three net) drilled to date and another four to six (3 to 4.5 net) wells scheduled to be drilled before year-end 2009.

In addition, Reliable said it is nearing the completion of its planned 2-D seismic survey whose results it will use to select the exploration drilling locations.

It is expected that a 3-D seismic survey planned for the South Kirkella pool will

commence shortly and enable proper delineation of the pool size.

The company achieved a 420 per cent increase in production during the third quarter and a 224 per cent increase yearto-date, compared with 2008. This was a result of Bakken oil production in Kirkella.

Production for the quarter averaged 82 barrels of oil equivalent (boe) per day compared with 16 boe per day for the third quarter in 2008 and the company exited the quarter at 124 boe per day of oil and natural gas production.

For the three and nine months ended Sept. 30, 2009, the company had negative cash flow of $230,000 and $1.26 million, respectively. Reliable reported a thirdquarter net loss of $1.23 million and a slight profit of $90,000 for the nine-month period.

Capital expenditures for the third quarter totalled $1.94 million and included completion and equipping activities of $707,000 and land acquisitions of $1.12 million. This compares with capital expenditures of $388,000 in 2008. The company added a further 11,495 (net) acres of undeveloped land in the quarter while lands under option decreased by 542 (net) acres.

During the third quarter, Reliable commenced negotiations on a private placement and joint venture with Crescent Point Energy Corp. The private placement, totalling $5.2 million, included $4.8 million by Crescent Point, while the joint venture resulted in a contribution of lands and cash by Crescent Point for a 25 per cent working interest in the joint-venture area. The private placement and joint venture were finalized on Oct. 2.

As well, Reliable commenced negotiations on the acquisition of Element Energy Canada Ltd. The acquisition, finalized on Oct. 22, resulted in the issue of 11.03 million shares of Reliable to shareholders of Element.

Element’s assets consisted of $1.5 million in cash and 1.4 sections of land in Alberta.

— DAILY OIL BULLETIN

SASKATCHEWAN WELL ACTIVITY DEC/08 DEC/09

WELL LICENCES

299

235

DEC/08 DEC/09

▼

WELLS SPUDDED

183

132

DEC/08 DEC/09

▼

WELLS DRILLED

215

171

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • February 2010

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February 2010 • OIL & GAS INQUIRER

11/13/2009 9:36:31 AM

Northern Frontier

TransCanada CEO Hal Kvisle still sees a need for Arctic gas supply

Photo: Joey Podlubny

by Elsie Ross

TransCanada says well decline rates indicate a future market for both Mackenzie Delta and shale gas.

Future natural gas supply rather than demand is TransCanada Corporation’s biggest concern despite the huge potential of North American shale gas, says the company’s top executive. “I am not yet ready to conclude that the long-term gas supply for North America is in the bag,” Hal Kvisle, president and CEO, said in a 2009 yearend interview.

TransCanada is a player in two massive projects to bring Arctic region natural gas by pipeline to consumer markets in the United States. “I do acknowledge we have more reserves and potential reserves available than we ever thought, but the big question is, at what rate is it going to come out of the ground, and is it going to be enough to not only sustain flat production but also meet what I think is going to be a one or two [billion cubic feet] a day per year growth in demand due to the power sector?”

With existing decline rates, simply to maintain current production over the next five years will require a total of 75 billion cubic feet (bcf) per day of gas to be brought on stream in North America (Canada, the United States, and Mexico) with about 29 per cent of that coming from

shale gas and the remainder coming from conventional gas plays.

“That’s an enormous amount of conventional drilling required [to maintain current production],” said Kvisle, noting that in Alberta average wells drilled do not have large reserves. While the average

“Over a five-year planning period if you need 75 bcf, I don’t think it’s too hard to see how you can fit five bcf a day from Mackenzie and Alaska into that overall equation.”

T he TransCanada CEO ack nowledged that the additional northern gas could result in lower natural gas prices than would otherwise be the case. Kvisle, though, suggested that the additional gas flowing through the TransCanada system will reduce toll rates for all producers.

“People in western Canada actually may be better off to see that northern gas on stream than not.”

Shippers on the TransCanada mainline have faced higher tolls as volumes out of western Canada have steadily declined to 5.2 bcf per day in 2008 from about 6.5 bcf per day in 2005. In 2010, the long-distance toll will increase to $1.60 per gigajoule from $1.19 in 2009.

TransCanada expects mainline tolls to stabilize and even to come down as production from the Montney and Horn River in northeastern British Columbia come on stream from 2011 to 2015. The company already has commitments of 2.5 bcf per day, he noted.

However, even at $2 per gigajoule, the mainline toll would be competitive with

TransCanada expects mainline tolls to stabilize and even to come down as production from the Montney and Horn River in northeastern British Columbia come on stream from 2011 to 2015.

annual decline in western Canada is about 20 per cent, in the U.S. Gulf of Mexico the rate is 35 to 40 per cent, he pointed out.

Kvisle also challenged those who have argued that with the advent of the shale plays in Canada and the Lower 48 States, the Mackenzie and Alaska pipelines from the Arctic (which will transport a total of about five bcf per day) will no longer be needed.

expensive new pipelines that would be required to get new gas supplies to market, said Russ Girling, TransCanada’s COO. “Our view would be that the resources in the Western [Canadian] Sedimentary Basin, whether it be shale or tight gas or conventional, is competitive with any other place in North America,” he said.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • February 2010

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Central Canada

Canada’s gas export decline was the biggest since at least 1985

Photo: Joey Podlubny

by James Mahony

Gas exports have declined to all major U.S. markets, including the Midwest, Northeast, and West Coast.

A nearly 11 per cent drop in Canada’s natural gas exports this year is the steepest decline since t he National Energ y Board (NEB) began tracking exports in 1985. While the 10.76 per cent drop only ref lects figures from January to September 2009, it does not bode well for full-year 2009 export volumes, which will come out in this year.

Using another period—November to September—the board estimated the drop in gas exports between 2008 and 2009 at about 10.4 per cent.

The record decline in volumes on top of plunging prices for Canada’s gas exports resulted in gas export revenues for the first three quarters of 2009 falling 55 per cent to $11.57 billion from $25.97 billion a year earlier. Average prices fell 51 per cent to $4.28 per gigajoule.

One of the largest declines in Canada’s gas exports occurred in 2003, when volumes dropped 7.6 per cent, to 98.92 billion cubic metres from 107.05 billion cubic metres the previous year. Drilling declined significantly as prices (the average market price in Alberta) dropped to $3.68 per gigajoule from $5.12 in 2001.

The drop is also evident in falling volumes on Canadian gas pipelines, according to Karen Morton, a natural gas analyst with the board. “Our throughput numbers showed declining volumes on a number of Alberta pipelines serving the competitive [U.S.] Midwest region,” she noted. “If we look at TransCanada’s m a i n l i n e o r Fo o t h i l l s P i p e l i n e s ’ Saskatchewan line, their throughput volumes are also down.”

Flows to markets in the western United States are also down, as are those on the Iroquois Pipeline into the U.S. Northeast. Morton attributed the drop in gas exports to several factors, including falling demand caused by the recession, declining gas output in western Canada, and competition from U.S. shale gas supplies.

Wit h t he ongoing recession, she said mainly industrial demand for gas is down in North America compared to previous years. When it comes to competition from U.S. shale gas, it’s primarily southern gas from deposits like Texas’ Barnett shale that is taking a toll. “That’s providing considerable competition in

some of our key Canadian markets in the [U.S.] Midwest and the U.S. Northeast,” Morton said.

In the near term at least, the NEB is not expecting western Canada’s gas supply situation to change much, and is forecasting a continuation of declines in volumes, at least until 2011, based on NEB gas supply models. Meanwhile, rising demand for gas within Canada, particularly from Alberta’s oilsands, will leave less gas available for export, Morton said.

“Less gas being produced and more being used in Canada will result in a net decline in exports,” she said. In an interview, Morton agreed that the unfolding shale gas picture in the United States does not bode well for Canadian gas exports, still less for gas destined for northeastern markets, where the emerging Marcellus shale lies.

Much depends on winter weather, and if the recent cold snap is a sign of things to come, it could mean stronger demand, at least this season. While normally good news for Canadian gas exporters, cold weather might have less impact this year, given the currently high levels of gas storage in the United States. “There is ample gas in storage now, so [U.S. electric] utilities will make the economic decision of what fits their portfolio,” she said.

Broken down by region, some parts of the United States still get the lion’s share of Canada’s gas. In the January-to-September period of 2009, the U.S. Midwest received 42.2 per cent of Canadian gas exports, while the U.S. Northeast took 29.3 per cent. Together, these regions got 71.5 per cent of Canadian gas.

In the same period in 2008, the same two regions consumed 73.1 per cent of Canada’s gas—the U.S. Midwest burning 41.2 per cent, while the U.S. Northeast received 31.9 per cent. California, at least, appears to be using less gas, or possibly just less Canadian gas. Its share of Canadian exports in the first nine months of 2009 was 11.6 per cent, versus 14 per cent in the 2008 period.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • February 2010

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International

Photo: Savanna Energy Services Corp.

Savanna announces Australian deal along with its 2010 capital plans

In Australia, Savanna’s drilling and workover rigs are contracted for an initial term of five years.

Savanna Energy Services Corp. is making its first foray into Australia. The Calgary firm will send two drilling rigs from its Canadian fleet and construct two builtfor-purpose workover rigs that will all be deployed in a coalbed methane (CBM) to liquefied natural gas (LNG) project in Queensland.

The total value of the deal between the Canadian service company and Australia Pacific LNG Pty Limited (APLNG) is expected to be in the range of C$203 million. All costs relating to mobilization of the rigs into Australia will initially be borne by Savanna, and recovered over the contract term.

The contract represents the first expansion of Savanna’s hybrid drilling operations beyond North America, and the company said it will continue to extend efforts in expanding its international presence moving forward.

“While domestic North American activity currently remains focused on deeper, unconventional plays, there remain substantial international opportunities to deploy Savanna’s hybrid drilling technology in areas where deeper

unconventional development is far less pervasive, and local natural gas and oil supply dynamics create a more stable activity and demand base for our equipment,” said Ken Mullen, president and CEO of Savanna.

On Dec. 23, Savanna said both the drilling and workover rigs destined for Australia are contracted on a 365-day (24-hour) basis for an initial term of five years, with an extension option and an option to add further rigs as the project grows. Savanna will also provide ancillary equipment and services to APLNG, which is a 50-50 CBM to LNG joint venture between Origin Energy Limited and ConocoPhillips.

Given Australia’s growing demand for CBM, Savanna said these rigs are intended for permanent deployment in Australia.

Based on CBM development plans in Australia overall, Savanna expects to further deploy additional hybrid rigs to the country. “Savanna’s management believes the hybrid technology it possesses is ideally suited to large-scale development of Australia’s substantial CBM resources,” the company stated in a news release.

Todd Creeger, APLNG project director, said the awarding of the rig contract was another milestone in the project and that the Savanna contract will provide for additional drilling and workover rigs to deliver the safest, most efficient, and most cost effective wells.

“Importantly, these new rigs reduce the environmental impact on the land as they require a much smaller footprint for each well,” he said.

Under terms of the contract, Savanna will modify two of its patented hybrid drilling rigs capable of drilling with coiled tubing or conventional drill pipe utilizing an integrated top drive. “The modifications, though extensive, are targeted to address local transportation and operating conditions in Australia,” Savanna said. “The operating advantages and depth ratings of the hybrid rigs remain unchanged and are key to the intended operations of APLNG.” The workover rigs to be supplied to APLNG will be new builds, and are significantly different than Savanna’s built-forpurpose Canadian and U.S.-based fleets.

The first hybrid and workover rigs are targeted to commence operations on location on Sept. 1, 2010, with the second set following on Dec. 1, 2010.

Meanwhile, Savanna also announced that its 2010 capital program is expected to be approximately $46 million. The prog ra m w il l foc us on sustena nce, maintenance, and incremental capital, including the capital required for the deployment of the rigs under the APLNG contract. Capital spending by Savanna through the first nine months of 2009 reached $56.14 million.

Upon completion of the capital program, and subject to any additional rig manufacture, acquisition, or transfer, Savanna will operate 2 drilling rigs in Australia, 4 in Mexico, 17 in the United States, and 86 in Canada (including 4 surface setting and 5 coring rigs). The company will also operate 2e workover rigs in Australia, 8 in the United States, and 66 (plus 8 coil service units) in Canada.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • February 2010

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Eliminates rod and tubing wear

www.cjsflatpak.ca

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JOB Careers in the Oilpatch

Alasdair (Ally) McLean Age: 30 Training: Instrument technician, technical diplomas in instrumentation and aeronautical engineering, bachelor of electrical and electronics engineering Title: Field service representative Company: Solar Turbines

What attracted you to a complex technology like turbines?

I was a Lego kid, building big models like a truck and a plane. I also loved the A-Team [television series], how Mr. T could make a tank out of a forklift with just a rivet gun. Making and fixing stuff comes naturally to me.

What’s your education and training?

In Scotland, I apprenticed as an instrument technician for a chemical manufacturer and later in avionics for British Airways. I also earned my technical diplomas at that time. When I was 25, I came to Canada. Solar hired me, and it paid for my engineering degree. I completed the degree by correspondence from the University of Sunderland where my father also studied engineering.

Normally, that takes about six years, Fortunately, the university gave me credits for my previous education, so I finished in three years. Anyone who wants to go that route should be prepared for a challenge—it’s not easy to study every day, especially after you’ve already been working in the field for 12 or 14 hours.

What’s your job like?

I’m based in Edmonton but work from coast to coast. I spend a lot of time at remote locations. For instance, I worked for nearly three months at Norman Wells [in the Northwest Territories], overhauling and upgrading three generators that supply power to the town. When something goes wrong with the equipment, there’s a lot of pressure. No one likes to see their production stopped. In the field, I get a lot of overtime, but the pay is good.

Photo: Aaron Parker

How would someone get into the gas turbine field?

It’s not easy. Working with this equipment requires extensive mechanical and electronic skills. Although I didn’t plan to work with gas turbines, my instrumentation and avionics training provided an almost ideal preparation. There are very few turbine schools, and they focus on aviation technology. Quite a few of Solar’s technicians come from the airlines. Ever since I’ve been with the company, we’ve had openings for qualified people.

Where do you see your career going in future?

In my own case, the engineering degree probably opens up some options.

However, any experienced field service representative with Solar can move into design, sales, or management. The choice is pretty much up to the individual.

OIL & GAS INQUIRER • February 2010

51

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Oilfield Buildings • Pipe Insulation • Utilidors Tank Insulation • Barrel Docks • Noise Barriers

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• (4) snubbing units on (2) ‘07, ‘05, ‘04 freightliner Tri/A • Rig assist Snubbing unit on ‘02 freightliner • (3) pump units on ‘09, ‘08, ‘06 Freightliner, T/A • (4) picker/deck trucks –’08 Tri, (2) ’06 T/a, ’05 T/a Freightliner w/ Hiab 300-3 • (3) dog house – ’09 Ryker 30' T/a w/ isuzu 25kw; ’06 Don adams 30' T/a wDeutz ‘06 30' T/A w/ Deutz • (3) Bop – double gate 7 1/16" • Forklift – Daewoo GP25, air tire, propane • Misc – spools, plug valves etc., offices

photos/specs - www.joinersales.com contact: Mr. Kevin Joiner 780.945.0256

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52

February 2010 • OIL & GAS INQUIRER

Tools of the Trade

TOOLS

OF THE TRADE A LOOK AT NEW TECHNOLOGIES

Hex-Hut Shelter System

chloride material. A shelter folds down into two bags with a collective weight of 170 pounds. One or two people can transport a Hex-Hut, then set it up in less than 10 minutes when conditions are favourable. The invention fits very well on any steam assisted gravity drainage or other in situ thermal construction project as well as pretty much anywhere contractors are building facilities and pipelines.

What is a Hex-Hut Shelter System?

A Hex-Hut Shelter System is a lightweight, robust, durable, portable, temporary shelter that is reusable. Every unit is hexagonal in shape like a giant umbrella, with six independent walls made out of fire-retardant polyvinyl

Do you have future development plans for Hex-Hut? Absolutely. I have a few more ideas that will complement the Hex-Hut Shelter System. The product has evolved significantly since the first prototype. As an inventor, I am always looking for ways to improve the design.

Photos: Hex-Hut Shelter Systems Ltd.

Who is Hex-Hut Shelter Systems Ltd.?

We supply portable welding shelters, mainly for pipeline construction and oil and gas facility installs. The company is family owned and operated, based in Calgary. Before founding Hex-Hut Shelter Systems in 2003, I spent 27 years as a pressure welder, working on all types of energy projects across western Canada. In my experience, the field shelters supplied to welders were typically cumbersome, uncomfortable, and at times downright unsafe.

What are the competitive advantages of this product?

A Hex-Hut Shelter System, due to its unique design, will have the same configuration, interior room, and overhead clearance regardless of the elevation or slope of the pipeline, steel, or terrain. There’s no conventional square frame that requires the ground to support it. Instead, our shelters can be attached to virtually any pipeline or structural steel by a patented steel cleat. The system adapts easily to any “tube and clamp” scaffold system, which minimizes the need for a skilled tradesman, expensive lifting equipment, and the single-use hoarding material that ends up in a landfill. Pins and lanyards keep the sections together, so there are no nuts, bolts, or small tools to lose in the snow or mud.

The Hex-Hut can be used regardless of pipe size or the location of the pipe or structural steel. This flexibility allows people working inside the structure to manipulate their work environment to suit their needs and the requirements of the welding process without burning the structure down.

Answered by Mark Moroney, founder and VP operations of Hex-Hut Shelter Systems Ltd.

OIL & GAS INQUIRER • February 2010

53

Political Cartoon

Advertisers' Index 1174365 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . 30

Crompton Western Canada Inc . . . . . . . . . . . . . 42

Northstar Energy Services Inc . . . . . . . . . . . . . . 4

Allan R. Nelson Engineering (1997) Inc . . . . . . . . . 5

DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . 34

Annugas Compression Consulting Ltd

Diversified Glycol Services Inc . . . . . . . . . . . . . 26

. . . . . . . . . . . . . . . . . . . . . . . . . . Inside Back Cover

Oil Lift Technology Inc . . . . . . . . . . . . . . . . . . . . . 5

dmg world media . . . . . . . . . . . . . . . . . . . . . . . . 24

BC Resources Expo . . . . . . . . . . . . . . . . . . . . . . 26

OilPro Oilfield Production Equipment Ltd . . . . . 42

Eagle Drilling Services Ltd . . . . . . . . . . . . . . . . . 30

Bear Slashing Ltd . . . . . . . . . . . . . . . . . . . . . . . 48 Bilton Welding and Manufacturing Ltd . . . . . . . . . 7 Black Sivalls & Bryson (Canada) Ltd . . . . . . . . . 44 Brews Supply Ltd . . . . . . . . . . Outside Back Cover Brother’s Specialized Coating Systems Ltd . . . . 10 Brownlee LLP . . . . . . . . . . . . . . . . . . . . . . . . . . 46 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . 11

Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . 36 Fit Right Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . 40/41 Hex-Hut Shelter Systems Ltd . . . . . . . . . . . . . . . 17 Joiner Sales Corp . . . . . . . . . . . . . . . . . . . . . . . . 52 Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . 26

Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . 30 Platinum Grover Int. Inc . . . . . . Inside Front Cover Propak Systems Ltd. . . . . . . . . . . . . . . . . . . . . . . 3 Prostate Cancer Canada Network . . . . . . . . . . 44 RTS Services Inc . . . . . . . . . . . . . . . . . . . . . . . . 44 Systech Instrumentation Inc . . . . . . . . . . . . . . . 42

Canadian Standards Association . . . . . . . . . . . . 21

LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . 36

CARES Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . 46

Tank Gauging Systems . . . . . . . . . . . . . . . . . . . 24

CJS Coiled Tubing Supply . . . . . . . . . . . . . . . . . . 50

MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . 24

Trans Peace Construction (1987) Ltd . . . . . . . . . 52

Cover-All Alberta . . . . . . . . . . . . . . . . . . . . . . . . . 5

Northern Alberta Institute of Technology . . . . 34

Triple D Technologies Inc . . . . . . . . . . . . . . . . . . . 21

Crimtech Services Ltd . . . . . . . . . . . . . . . . . . . . 36

Northgate Industries Ltd . . . . . . . . . . . . . . . . . 46

Vertigo Theatre Society . . . . . . . . . . . . . . . . . . 34

54

February 2010 • OIL & GAS INQUIRER

Electrical Supplies when you need them

Automation

Brews Supply Ltd. – offering a broad range of electrical products, in stock and ready to ship!

Wire Handling

With over 80 years in business, Brews knows what the oilpatch needs from an electrical supply company.

Distribution Equipment

Heating Equipment

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Ask About our “Hot button” Service

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Utility Products

Enclosures

Thousands of Applications Hundreds of Labels One Label Printer BMP™ 71 Label Printer.

The best features and functionalities of Brady’s portable label printer are now combined into one easy-to-use, top-of-the-line portable thermal transfer printer – Brady’s NEW BMP™ 71 printer.

Whether you need ¼” self-laminating wire marker labels or 2” wide vinyl pipe marker labels, you only need ONE label maker.

With the fastest print speed on the portable printer market, the BMP™ 71 printer is designed to help you get your job done quickly and efficiently. It can print on over 400 label parts – so whatever label size or colour you need, we got you covered.

For more information visit www.brewssupply.com

BREWS Supply Ltd. Toll Free 1.800.661.6884 www.brewssupply.com Calgary (Head Office) 12203 40th St. S.E. PH 403.243.1144 Edmonton 18003 111th Avenue N.W. PH 780.452.3730