Alberta Oil June 2012 by Venture Publishing

GLOBAL REPORT

The Business of Energy

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The liTigaTors you don’T wanT To come up againsT should be yours.

As the oil and gas industry continues to help meet our world’s energy demands, technological development plays a vital role. Protecting your competitive position by patenting and maintaining trade secrets is critical. But protecting innovation is only half the story. Sometimes you need to enforce your intellectual property and commercial rights. Decisively. Since 2008, the Commercial Litigation Group at Borden Ladner Gervais LLP (BLG) has scored the bull’s eye as the leading firm for commercial litigation in Calgary, as ranked by Lexpert.* So when it comes to major commercial and IP litigation in the oil and gas industry, chances are we will be at the table. Best we be on your side. To find out how we can help you protect your intellectual assets, contact: Frank Tosto | 403.232.9435 | ftosto@blg.com Kevin laroche | 403.232.9661 | klaroche@blg.com david madsen | 403.232.9612 | dmadsen@blg.com evan nuttall | 403.232.9403 | enuttall@blg.com christine collard | 403.232.9682 | ccollard@blg.com

blg.com *As noted in The Canadian Legal Lexpert ® Directory 2011. Lexpert ® is a registered trademark of Thomson Reuters Canada Limited. © Copyright Thomson Reuters Canada Limited and its Licensors. All rights reserved.

June 2012

volume 7 issue 12 CONTENTS

Cover Package The 100 + Energy Service 50 A healthy price for a barrel of oil and the opposite for natural gas were big stories in 2011. So, too, was the rush to reach new markets and the continued emergence of horizontal drilling and hydraulic fracturing. While it wasn’t all good news for the patch, Alberta Oil’s annual roundup of Canada’s top-performing oil and gas producers – and for the first time, its energy service firms – shows that the sector is surging, despite some bumps along the journey.

2011 was a year of growth for the oil and gas industry. But access to new markets and labor remain key challenges for the sector

A comprehensive overview of Canada’s top-performing oil and gas producers and energy service firms

Hugo Chavez is losing his hold on power in Venezuela. Should Alberta’s oil and gas sector be worried?

Turbulent Times

Living Large

Follow the Leader

By Roger Tissot

By DR. Geoff Hill

STEP CHANGE

A handful of players try to unlock a 400 billion barrel mystery

Canadian firms fan out to emerging markets to build businesses

An energy MBA program is bringing executives from around the world to Calgary

by JEFF LEW IS

By Bever ly Cramp

Raising a Giant

Foreign Exchange

Globetrotters

By Steve Macleod

82 JUNE 2012

volume 7 issue 12

JUNE 2012

CONTENTS

Departments 8 Editor’s Log

2011 was a year of many highs, and some lows, for the oil patch 13 Observer

Harvest Operation’s Rob Pearce talks about being an Asian subsidiary; how low can natural gas go? off-road trucking in the patch 24 DOSSIER

Could oil sands royalty sharing secure B.C. support for Northern Gateway?

28 LEADING EDGE

Can the oil sands be extracted without water? Imperial Oil thinks so 32 5 THINGS

Canada should love, not loathe, foreign investment 34 ENTERPRISE

zEroCor Tubulars Inc. takes on wellbore corrosion 36 SUITE LIFE

Populating your board with more women can improve the bottom line

26 EYE ON OILSANDS

How shoddy statistics can lead to shoddier policy

cover type by Tom White

22 hot TopicS 94 DIVIDENDS

Natural gas stocks are a long way from the point of maximum pessimism By Er ic Nuttall

96 CONTRAST

Petrobank and PetroBakken are joined at the hip, but moving in different directions 98 vantage

Engaging aboriginal communities could help solve a labor shortage and allow Alberta to be a global energy leader By J i m carter

Learn more about the companies that made The 100 + Energy Service 50 lists at www.100.albertaoilmagazine.com

www.albertaoilMAGAZINE.com

CONTENTS IMAGES EDDIE GUY, KYLE METCALF, BRYCE MEYER, CHRIS BEAUCHAMP AND KALEY MCKEAN

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EDITOR’S LOG

Safe Harbor

Despite a sea of economic uncertainty, growth reigns in the oil patch When ALBERTA OIL FIRST DID THIS

exercise in 2010, ranking Canada’s topperforming oil and gas companies, the sector was in a very different place. It was trying to get back on its feet after a global recession had hit it hard – resulting in plummeting profits and shelved projects. The net income of the 100 companies on that first list had nosedived from $35.8 billion in 2008 to $8.36 billion in 2009, and balance sheets had plenty of red ink on them. While the industry was optimistic that things would go its way again, there was uneasiness about how long the pain would last. Our third annual rankings paint a very different picture. Pain has been replaced (in most cases) by profits. Revenues of the 100 companies listed – at $184 billion – are almost what they were in the heady days of 2008 before the global economy imploded. Profits are up, too, although the total for 2011 – $18.7 billion – isn’t close to the 2008 figure. And production, both for oil and natural gas, continues to increase. So growth is the mantra once again for the Canadian oil and gas industry.

www.albertaoilMAGAZINE.com

The financial and production figures you will find in the lists contained in this issue reflect that. The trick, though, is how to sustain the growth. As Dr. Geoff Hill, Deloitte Canada’s leader for its national oil and gas sector group points out in a piece you can find on page 40 of this issue (“Turbulent Times”), it won’t be easy. Hill and Deloitte, who I’m pleased to say was our partner in putting together The 100 + Energy Service 50 lists, note that labor shortages, diversifying markets for Canada’s oil and gas and continuing to attract foreign capital are challenges the industry must overcome if it wants to stay profitable for the long haul. Those issues aren’t new and the sector hasn’t had much success solving them in the past. But with another economic meltdown hovering, the oil patch must redouble its efforts to tame these maladies. Did you notice that I wrote “The 100 + Energy Service 50” above and not just “The 100”? Alberta Oil has beefed up its rankings this year to include the energy service sector. It was the right time to do it. For every barrel of oil and cubic foot

of natural gas produced in Canada, there is an army of energy service outfits that helped make it happen. This sector is a huge part of the patch, employing thousands of people and creating a great deal of wealth in Canada. Our list ranking 50 of Canada’s top-performing energy service firms provides our readers a window into how big of an impact those firms have on the oil patch.

Darren Campbell

dcampbell@albertaoilmagazine.com

In the next issue of AO TransCanada and the trouble with the Mainline

Unconventionals drive service sector M&As

Should Ontario’s Rust Belt be looking west for work?

Environmental services goes from a niche to the mainstream

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The Business of Energy volume 7 issue 12 Publisher Ruth Kelly rkelly@albertaoilmagazine.com Editor Darren Campbell dcampbell@albertaoilmagazine.com Senior Editor jeff lewis jlewis@albertaoilmagazine.com Assistant Editor STEVE MACLEOD smacleod@albertaoilmagazine.com Copy Chief Kim Tannas Art Director kim larson Associate Art Director ryan Girard Assistant Art Director Andrew forbes Production Co-ordinator Betty-Lou Smith Production Technician Brent Felzien Web and Systems Architect Gunnar Blodgett

Investing in South America

Assistant Director of Circulation sharlene clarke Circulation Co-ordinator Jennifer King Assistant Publisher Andrew Williams Controller ally sperle Accounting Assistant Glenna Gravel Executive Assistant Sharlyn Gordon Vice-President Sales Anita McGillis amcgillis@venturepublishing.ca Sales Assistants Karen Crane, kassandra mitchell Advertising Account Executives Dennis McCormack dmccormack@venturepublishing.ca lisa richards lrichards@venturepublishing.ca Tara Giebelhaus tgiebelhaus@venturepublishing.ca Matt Cook mcook@venturepublishing.ca ELLEN FRASER efraser@venturepublishing.ca

Alberta Oil is published 12 times per year by Venture Publishing Inc. www.albertaoilmagazine.com Publishing Office/Edmonton Sales 10259 105 Street Edmonton, AB T5J 1E3 Telephone: 780-990-0839 | Fax: 780-425-4921 Calgary Sales #4 2526 Battleford Avenue SW Calgary, AB T3E 7J4 Telephone: 403-228-4337 | Fax: 403-217-6588 Contents copyright 2012 by Venture Publishing Inc. Content may not be reprinted or reproduced on websites without express permission of the publisher. ISSN:1912-5291 Subscription Prices One year: $59.95 | Two years: $109.95 | U.S.A. one year: $79.95 | International one year: $99.95 Send subscription requests and address changes via email to circulation@albertaoilmagazine.com or call toll-free: 1-866-227-4276 ext. 237 Undeliverable mail should be directed to the publishing office: Venture Publishing Inc. 10259 105 Street, Edmonton, AB T5J 1E3 or via email to circulation@albertaoilmagazine.com Canadian Publications Mail Product Sales Agreement #40020055 Printed in Canada by Transcontinental Graphics This magazine abides by the editorial standards set by the Canadian Society of Magazine Editors. We do not publish unsolicited articles and material sent will not be returned. Media releases may be directed to mediareleases@albertaoilmagazine.com. Occasionally, Alberta Oil makes its names and addresses available to carefully screened organizations that want to let you know about a product or service that may interest you. If you do not wish to have your name included, please send an email to circulation@albertaoilmagazine.com.

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Observer the ask

NEWS

NUMBERS PEOPLE

PLACES

sector that needs large ongoing capital support and investment. Without it, this industry and this country’s overall economic position would be a small fraction of what it is today. AO: What does that investment do for the industry and Alberta? RP: It supports the development of resources that would

otherwise lag. We’ve got lots of opportunity in Canada and if we only looked to the domestic market for the capital to execute on those opportunities, we’d be way short. That investment creates jobs, economic activity and wealth in Alberta and across the country. AO: Is there much difference in how companies in the Pacific Rim conduct business compared to the way you’re used to doing business in Canada? RP: There are some differences. But KNOC is a sophisticated

organization. South Korea itself has a capitalist way of doing business. Fundamentally there is a lot more in common than you might think. For us the difference is not so much that it’s a Korean business. Effectively [KNOC] is a Crown corporation. They have a longer-term view than others might have and different drivers as well. AO: Is Asian investment in Canada’s oil and gas industry here to stay? RP: We see that trend continuing. For many of these coun-

Business as Usual For Rob Pearce and Harvest Operations, Asian investment is a blessing, not a blight Rob Pearce has a bird’s eye view of a Canadian business trend – increasing Asian investment in the oil patch. In 2009, the Korean National Oil Corporation (KNOC) bought Calgary-based Harvest Operations Corp. Foreign ownership of Canada’s oil and gas resources has made some Albertans uneasy. But Pearce, Harvest’s chief operating officer, says Asian investment is good for Alberta and Canada. Alberta Oil: We recently did a survey where more than 50 per cent of Alberta respondents felt there is too much foreign ownership in the province’s oil and gas industry. Should Albertans be concerned? Rob Pearce: When you look at the shareholdings of supposedly

Canadian companies, there is lots of foreign ownership there. It’s just more in the background and a little more passive. This is a

PHOTOgraph bookstrucker

tries their needs for energy are growing rapidly and Canada has a tremendous asset base with a lot of growth opportunity to help meet their needs. We’ve got more experience as a hydrocarbon exporter, a government that believes in hydrocarbon exports and is open to foreign investment. That can’t be said of all countries. We’ve got regulated and safe working environments, low political and fiscal risks, and there is a rule of law here. That provides a lot of comfort for investing countries. AO: Myunghuhn Li replaced John Zahary as Harvest’s president and CEO in January. How has the succession gone? RP: Change at the top always attracts a lot of attention.

The thing to keep in mind is we’ve got over 1,000 employees when you include the refineries. There is a lot of continuity within the employee ranks. We’ve got a very experienced management team and a long history with the assets and the company. We’re executing on our 2012 capital plan. Wells are being drilled and oil and gas is being produced and sold. It’s really business as usual through this CEO transition.

June 2012

OBSERVER

Creepy Report says pipeline reviews are being clogged up by scoping sprawl The oil AND GAS INDUSTRY CAN’T

blame green groups and aboriginal people solely for the slow regulatory progress of some key pipeline projects. A spring report released by the C.D. Howe Institute entitled Unclogging the Pipes: Pipeline Reviews and Energy Policy, found that one of the key factors leading to lengthy regulatory reviews of proposed pipelines in Canada is “scope creep”. This

refers to regulators allowing factors that are not relevant to a specific project to be considered during the review. Those factors often include broad economic, social and environmental issues – like the role TransCanada’s Keystone XL pipeline will play in the growth of the oil sands and in increasing Canada’s greenhouse gas emissions. The report’s author, Joseph Doucet – the University of Alberta’s School of Business interim chair – says that while greens and aboriginal groups have played a large role in enabling scope creep, the oil and gas industry hasn’t been blameless. One example: some Keystone XL proponents suggest the controversial conduit should be built because oil sands crude is ethical compared to crude produced by states such as Libya or Nigeria. Doucet argues those kinds of issues should not be debated during specific

22%

pipeline reviews. “It’s quite possible tribunals have become more generous in the way in which they make these decisions. That may be the result of erring on the side of letting too many people speak as opposed to not enough,” Doucet says. “The regulator just really has to be firm in saying this is the scope of the mandate and this is not.” Making Canada’s regulatory regime more efficient has become a goal of the Conservative government in Ottawa. Its zeal for regulatory reform comes from the potential pot of gold waiting for it at the end of the oil sands rainbow. Some studies estimate the oil sands will increase Canadian gross domestic product by nearly $800 billion between 2000 and 2020. In 2010, energy products accounted for approximately 22 per cent of Canada’s export revenues. But as oil sands production grows and more pipelines are built, that percentage will grow.

of Canada’s export revenues came from energy products in 2010

Bottom Line

A balanced Alberta budget hinges on rosy revenue projections from non-renewable resources Premier Alison Redford will have to deliver on her campaign promises following Alberta’s election on April 23. That includes a balanced provincial budget in 2013-2014. The Progressive Conservative government’s pre-election budget in February 2012 projected less than $1 billion in deficit for 2012-2013, and following a balanced budget, a surplus of $5.2 billion for 2014-2015. Roughly 43 per cent of Alberta’s forecasted revenue for 2012-2013 is expected to come from non-renewable resources, which makes projecting revenue an inexact science. The day the budget was released the price of West Texas intermediate (WTI) oil was US$99.88 per barrel. The price rose to $108.76 a month later, but was down to $96.13 on May 11. Those fluctuations can have a big impact on the province’s bottom line.

Provincial Budget Sensitivities 2012-2013

Change Oil (WTI US$/bbl) -$1.00 Natural Gas (Cdn$/Gigajoule) -$0.10 Exchange Rate (US¢/Cdn$) $0.01

Interest Rates Personal Income

-1% -1%

Net Impact (2012-13)

- $223 million - $28 million - $247 million - $223 million - $119 million

OBSERVER

Natural gas producers are hoping for a hot summer after enduring what CIBC World Markets says was “one of the most painful quarters for natural gas producers in over a decade.” During the first quarter of 2012, NYMEX prices averaged US$2.43 per million BTU, down 42 per cent compared to the first quarter of 2011. AECO prices averaged $2.98 per 1,000 cubic feet down 44 per cent compared to the first quarter of 2011. The forecasts that drilling activityIN THE WESTERN CANADIAN SEDIMENTARY BASIN (WCSB) will increase slightly is borne out by first-quarter rig utilization levels. According to Calgary-based investment boutique Peters & Co., 2012 first quarter rig utilization rates in the WCSB were 68 per cent compared to 67 per cent during the first quarter of 2011.

FLARING UP

Low natural gas prices aren’t all bad for the oil patch Environmental regulators have given natural gas producers in the United States until 2015 to figure out how to eliminate flaring from their operations. North of the border, CanElson Drilling Inc. already has a solution. The Calgarybased public company spent the better part of 2011 developing a bi-fuel engine that runs on diesel and compressed natural gas (CNG). The driller unveiled the patent-pending engine in January and a couple of months later acquired CanGas Solutions Ltd., a private company that specializes in the storage and transportation

of flared or stranded natural gas. Flaring gas is a tough industry practice for the public to accept. Why do companies waste so much of a valuable resource simply by burning it off? “Flared gas being burned is of no benefit to the public or the government,” says Randy Hawkings, president and CEO of CanElson. But with prices for the cleanest burning fossil fuel so low these days, it now makes more sense to burn natural gas as a fuel rather than flare it. “Would you take it out of the pipeline and not send it to market?” Hawkings asks. “Flared gas has no value.”

However, as CanElson has shown, running oilfield equipment on natural gas does have value. CanElson tested its bi-fuel engine on its drilling rigs. The CNG can replace up to 70 per cent of diesel consumed, but the engine can also run on 100 per cent diesel when natural gas is not available. The company plans on installing the bi-fuel engine on four of its 36 rigs in the first half of this year. Hawkings says he intends to make the engine available for service rigs and any other mobile piece of equipment in the oilfield. “There are a whole lot of diesel engines that can be retrofitted,” he says.

Fading Flame

2005

Surging production continues to knock the stuffing out of natural gas prices

10.93

In April, forward prices for natural gas traded on the New

York Stock Exchange dropped below US$2 per million BTU for the first time in more than a decade. Canada’s AECO natural gas pricing benchmark hasn’t fared much better. As new supplies of natural gas extracted from shale basins in North America raise fears of storage containment, prices for the “champagne” of fossil fuels have sunk like a stone. The last time natural gas in Alberta sat in double digits was July 2008, when the AECO price averaged $10.77 per gigajoule (GJ) for the month. What follows is a look at AECO’s wild ride.

2011

3.44

2009

3.12

2008

8.16 2007

7.06 2012

2002

4.46* *AECO price ($/GJ) Source: Natural Resources Canada

2012

1.71

1.85

(forecast)

OBSERVER

A glut of natural

CLEARING THE AIR

How carbon-heavy is the crude oil from the EU’s suppliers anyway? THE ALBERTA GOVERNMENT HAS

academic Andrew Brandt for the EU had the difference at 22 per cent. One issue Jacobs found when gathering data was the inconsistency in measuring gas flaring around the world. While Canadian companies must account for all the emissions from their extraction and processing – like flaring and venting natural gas – many foreign countries do not. A quick scan of the sources of the EU’s crude oil supply reveals a host of countries whose data for reporting emissions is anything but robust.

a new weapon to use as it fights to prevent the European Union (EU) from labeling oil sands crude as dirtier than other fuels in its proposed Fuel Quality Directive. In May, a governmentcommissioned study conducted by California-based Jacobs Engineering Group was made public. It determined the well-to-wheels carbon intensity of oil sands fuel from Alberta is within 12 per cent of the carbon intensity of crude oil from other regions refined in Europe. A 2011 study done by Stanford University

European Crude Supply 2010 Former USSR 38% Norway 14% Libya 9% Saudi Arabia 5% Iran 5% United Kingdom 4%

Nigeria 4% Iraq 4% Rest of Africa 2% Angola 2% Algeria 2% Other (incl. Canada) 11%

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GAS is eating away at Canada’s market share in the United States. According to the National Energy Board, revenues were $15.15 billion in 2010 – the lowest level for export revenues since 1999.

platts says that oRganization of petroleum exporting countries (OPEC) crude oil output climbed by 320,000 barrels per day in April compared to March to reach 31.71 million barrels per day. That increase came despite declining production from Iran, which faces U.S. sanctions in June that will make it harder to import oil from the rogue nation and could take more than three million barrels per day of Iranian oil off the market.

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Pembina PiPeline CorPoration

more than just PiPelines

Thank you! Alberta Oil extends its thanks to The 100 & Energy Service 50 Luncheon sponsors, ATB Corporate Financial Services, Deloitte, Haskayne School of Business and Rogers for making the first annual The 100 & Energy Services 50 Luncheon a great success.

with nearly 60 years experienCe, Calgary-based pembina pipeline Corporation is a well-managed and responsible transportation and service provider to north america’s energy industry. pembina owns and operates pipelines that transport crude oil, ngl, diluents and synthetic crude produced in western Canada; offers a full spectrum of midstream and marketing services that include an ngl infrastructure and logistics business with strategically located facilities in western Canada and in the premium ngl markets in eastern Canada and the United states; and, has a strong presence in the gas services and heavy oil sectors. our integrated assets and commercial operations enable us to offer services that support the energy sector along each step of the hydrocarbon value chain.

View exclusive web coverage of the event at: www.albertaoilmagazine.com/top100 Presented by: Sponsored by:

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OBSERVER

Connect

LIGHT ENDS

A round-up of the most popular stories from albertaoilmagazine.com

CLEAR AS MUD – May 2012

Net Worth

Which executives earned their money in 2011?

Being the CEO of a major oil and gas company is not for the faint of heart, as there is a lot of pressures that comes with the job. But being the top executive has it perks, and the pay is one of them. With salaries that hit seven figures, CEOs in the petroleum business are well-compensated for their troubles. But did their performance in 2011 match the hefty paychecks? Alberta Oil examined four CEOs from companies that made the top 10 in our annual ranking of the 100 top-performing Canadian oil and gas companies (see page 44).

With reference to your May article on the drilling fluids market, I was both amazed and flabbergasted that the largest, Canadian-owned drilling fluids company in the world was not mentioned. Q’Max Solutions Inc., headquartered in Calgary, Alberta, with worldwide operations and over 1,200 employees was somehow missed in your magazine’s due diligence. Considering our company has taken numerous, patented technologies − developed right here in good old Alberta − and successfully marketed them globally, makes it an unfortunate circumstance that a magazine called Alberta Oil failed to uncover this well-kept secret. I trust your next article on the players of the oil sands will make mention of Suncor. Tony Davis, managing partner, Q’Max Solutions Inc.

SOMETHING ABOUT HARRY Steve Williams President and CEO, Suncor Energy Inc. Salary (2011): $811,923

Suncor says: Williams, the firm’s chief operating officer in 2011, drew high praise in Suncor’s proxy to shareholders for helping it achieve “record performance in all dimensions of operational excellence, including the company generally exceeding production, availability and utilization expectations.” Alberta Oil says: Williams took over from his predecessor, Rick George, in May, so it’s too early to make a call on whether he’s earned his salary. But cost inflation on Suncor’s growth projects continues to worry the market. Williams will wrestle with that challenge in 2012. Asim Ghosh

President and CEO, Husky Energy Inc. Salary: $1,449,625

Husky says: In its information circular to investors, Ghosh earned high marks from Husky’s compensation committee for exceeding targets on return on capital, increasing cash flow and net earnings and for his “overall positive leadership of Husky.” Alberta Oil says: The market continues to undervalue Husky’s stock. But that’s no fault of Ghosh. The firm met or exceeded targets in all its key metrics in 2011. Ghosh deserves props for that.

www.albertaoilMAGAZINE.com

John Manzoni

President and CEO, Talisman Energy Corp. Salary: $1,481,077

Talisman says: Buried at the bottom of an assessment of Manzoni’s 2011 job performance in the firm’s information circular is this nugget: “Execution on major projects was a disappointment in 2011.” Alberta Oil says: How true. Net earnings rose by a mere $120 million compared to 2010 and oil production actually dropped by 11,000 barrels per day. All in all, it was an underwhelming year for Manzoni – and Talisman. Brian Ferguson

President and CEO, Cenovus Energy Inc. Salary: $1,068,750

Cenovus says: In its proxy, Cenovus was glowing in its praise of its president and CEO. “Brian Ferguson led Cenovus to a tremendous year, financially and operationally.” Alberta Oil says: You’ll get no argument from us on that assessment. Pick a metric – production, net earnings, cash flow, shareholder return – and Cenovus met or exceeded expectations in 2011. This is a chief executive making all the right moves.

Our June interview with Corridor Resources Inc. president Phillip Knoll, whose company plans to spud a well offshore in the Gulf of St. Lawrence, prompted some strong feedback. Corridor plans to drill in the region by 2014. Some, recalling the specter of the Macondo tragedy in the Gulf of Mexico, would prefer to see those plans shelved. At least one reader worried about the impact a disaster could have on local tourism. The St. Lawrence ecosystem provides a “unique habitat, favoring the proliferation of Krill. Krill are the reason the whales are there.” Alberta Enterprise Group president Tim Shipton revived an old criticism of Canada’s competitiveness with his article about Alberta becoming a global energy player. “Canada is too remote from markets and slow to respond to world energy needs to be a super-power,” one reader complained. Another added: “Nice article; not much substance.”

What You Were Tweeting* Agriculture outstrips oil sands land impact 13 clicks What the PC’s win means for Alberta’s oil patch 8 clicks Toll Battle: TransCanada vs. Ontario gas users 6 clicks A lifeline emerges for Arctic gas 4 clicks Five insights on doing business with China 4 clicks

*As of May 6, 2012

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OBSERVER

FREEZE FRAME

Giddy-up When spring breakup arrives, the oil patch must get mobile Photograph Chris Beauchamp The old adage that if you don’t like the weather in Alberta, just wait 10 minutes,

might be comforting for people during a spring storm, but it makes planning a rig move tricky. Spring breakup, which often turns prairie drill sites into soupy messes, can shut in remote areas of the province altogether, while weight restrictions of between 75 to 90 per cent of a legal load limit act as deterrent for other operators. Despite the extra costs of moving lighter loads and specialized equipment to operate on muddy leases, not all of Mullen Oilfield Services’ work in the spring occurs south of the border, where breakup is less of an issue. The Calgary-based company was at a lease just south of Grande Prairie on May 7 with a 25-person crew. Moving a crane drilling rig 20 kilometers – same operator, same field – was a two-day job. “That was 90 loads, which is a fairly high load count,” says Michael Kent, who works for Mullen on business development and special projects. “I would say the typical average would be closer to 40.” Mullen had two cranes, three bed trucks, a picker truck and eight-to-12 haul units on site. The heaviest load was the pump houses, which weighed between 110,000 – 125,000 pounds. The oversize loads were 12-feet wide and require additional axles on the trailer – 48 wheels in total. It’s not the kind of move you want to do in foul weather. AO

To view more images of this tear down from Grande Prairie photographer Chris Beauchamp, visit www.albertaoilmagazine.com/rigmove

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7590%

are the number of wheels on a truck-trailer hauling a pump house

of the legal axle weight on a wheel is allowed during spring breakup in Alberta

40 is the average number of truck loads needed to move a rig

JUNE 2012

dossier

Distant Star

Could profit-sharing get landlocked Alberta crude to the Pacific?

By Graham Thomson If only the proposed Northern Gateway pipeline

shipped $100 bills to the West Coast, life would be so much easier for Alberta. No protests, no legal challenges, no need for lengthy environmental reviews. British Columbians along the pipeline route would positively welcome a spill. As it stands now, so many environmental groups and First Nations are opposed to Enbridge Inc.’s $5.5-billion project that the pipeline might as well be shipping, uh, bitumen from the oil sands. But that actually might be one of the keys to unlocking public approval for the pipeline. At least that’s what some officials in the Alberta government think. They quietly argue that the real reason for opposition to the pipeline is not that it’s shipping oil but that it’s shipping oil sands oil. That, and the fact that British Columbians are not receiving a cut of the action for accepting all the risks of a pipeline spill. Therefore, some elements inside the recently-elected government of Alison Redford have come up with a two-pronged plan. The first is well known: Make the oil sands cleaner and more environmentally palatable by reducing open pit mines, reducing greenhouse gas emissions and increasing land reclamation. Make Alberta look as if it’s trying to be as “green” as B.C. “We don’t get access to markets without cleaning up the oil sands,” says one senior source who explains that is one of the tenets of Redford’s yet-to-be-clarified Canadian energy strategy. The second prong has been hinted at but never confirmed: Share bitumen royalties with B.C. No one in the Alberta government will admit to this publicly but it’s an idea that’s out there like a distant star. Look at it directly and it vanishes but it’s still there just on the edge of your peripheral vision. “There hasn’t been a discussion,” says the senior source, choosing his words carefully. “What there’s been is a kind of an opening up of the idea.” The idea is based on the not-so-secret fact that for all its resource wealth and entrepreneurial spirit, Alberta is missing one crucial element to ship its oil to China: access to the Pacific Ocean. Standing between the province and the Asian market is 1,000 kilometers of mountains, rivers and angry protestors. Getting over the Rockies and across the waterways is the easy part. It’s the human barrier that will prove the most difficult to overcome. That’s why the Alberta back door plan is to

www.albertaoilMAGAZINE.com

convince a majority of British Columbians that the pipeline is in their best interest. And nothing says best interest like money, jobs and prosperity. There’s talk inside Alberta political circles about helping B.C. build a bitumen upgrader in Kitimat, akin to the Progressive Conservatives of old under Premier Peter Lougheed helping build the grain terminal at Prince Rupert to get Alberta wheat to the world market. If Alberta can get its bitumen to the West Coast, the province would receive much more for its product than the discounted price it currently gets for landlocked bitumen. According to an analysis by the University of Calgary’s School of Public Policy, access to Asian markets could generate $27 billion worth of tax revenues to various levels of government between 2016 and 2030. It’s an oversimplification to say that Alberta and B.C. would split the difference between the landlocked price for oil and the world price, but it wouldn’t be a radically wrong simplification.

Nothing says best interest like money, jobs and prosperity. And while it would be unfair to say Alberta is trying to bribe its neighbor to the west, it wouldn’t be unfair to say the newly revived Progressive Conservatives under Redford are looking to Lougheed’s interprovincial generosity of the past for inspiration. But Redford is treading carefully. She might be firmly in control of the Alberta government, and pipeline-friendly Stephen Harper might have a majority in Ottawa, but their ideological ally, B.C. Premier Christy Clark, is heading down a bumpy road towards a provincial election in May of 2013. “There’s not going to be any discussions that go anywhere until after the B.C. election,” says the government source. But when the discussions start, Alberta will be trying to convince British Columbians that the Northern Gateway pipeline is figuratively, if not literally, stuffed with environmentally responsible $100 bills heading their way. AO

Graham Thomson is an award-winning provincial affairs columnist for the Edmonton Journal.

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EYE ON OIL SANDS

Data Dump How fudged numbers lead to bad policy By Jackie Forrest Understanding the energy sector

often requires navigating competing, chaotic and often confusing data sets. Figuring out the greenhouse gas emissions (GHG) from oil sands is one example. Wide-ranging estimates, differences in data quality, availability and collection all make getting the numbers right difficult. As a result, using these numbers for policy is challenging. Yet GHG policy directed at crude oil is advancing in some places. California has its Low Carbon Fuel Standard, and work continues on a European Fuel Quality Directive. In both cases, Canada, Alberta and industry participants strongly oppose the high-carbon label uniquely applied to oil sands. At a glance, the opposition is curious. Oil sands exports to these markets are currently small to nil. Why does Canada care so much? One reason is that numbers etched in policy, even if highly uncertain, are often perceived as more credible than others. Here’s an example: To support the U.S. federal renewable fuel standard, the Department of Energy’s National Energy Technology Laboratory estimated the life cycle GHG emissions for U.S. refined products in 2005. (Life-cycle GHG emissions include all emissions from crude oil – from extracting, refining, transporting and ultimately consuming the fuel). In a March 2009 report, the technology lab estimated life cycle GHG emissions from oil sands were 17-per-cent higher than the average crude oil consumed in the U.S for 2005. The value was

www.albertaoilMAGAZINE.com

higher than numbers found in other studies or operator reports. For example, the lab assumed 2005 oil sands mining and upgrading emissions were 134 kilograms per CO2 per barrel, and no source was provided for the estimate. Yet, according to company information, Suncor and Syncrude (the only commercial mining and upgrading operations in 2005) had emissions ranging between 100 and 120 kilograms per CO2 per barrel. By 2009, given that Shell Canada’s Athabasca Oil Sands Project had started up and the original two operators had become more efficient,

the industry average was in the range of 89 kilograms per CO2 per barrel. Add in GHG emissions from current operations, as well as the mix of oil sands products likely to be pipelined to the U.S. (a mix of synthetic crude oil and bitumen blends), and the current life-cycle GHG emissions are closer to six per cent higher than the average crude consumed in the U.S. Although the Department of Energy oil sands values do not reflect current oil sands emissions, they were nevertheless provided a level of credibility when they

were included in the final renewable fuels rule. What’s more, they are now often used to describe GHG emissions from oil sands in U.S. policy discussions. Take the U.S. State Department’s review of TransCanada Corp.’s Keystone XL project. The Environmental Protection Agency (EPA) complained that incremental GHG emissions from consuming oil sands crudes (instead of lower carbon crude oils that would be used in the absence of the pipeline) were not considered. Using the flawed values from the renewable fuels standard, the EPA says that consuming oil sands delivered via Keystone XL would generate an extra 27 metric tonnes of carbon per year. Later, these values were one of three sources used to describe GHG emissions from oil sands when the State Department issued its Final Environmental Impact Statement for the pipeline. A similar pattern is playing out in Europe. Its fuel quality directive assigns oil sands a life-cycle GHG emissions value 23-per-cent higher than for all other crude oils processed in Europe. Again, factor in the mix of oil sands products shipped from Canada (synthetic crude oil and bitumen blends) and life cycle oil sands emissions are more in the range of 11-per-cent higher than the average crude consumed in Europe. Canada needs to care about these policies. Singling out oil sands crude from all other high-carbon crudes is discriminatory, and policy can sometimes mischaracterize the resource’s emissions profile. This can lead to serious errors, because once in law, these numbers, much like bitumen itself, tend to stick. AO

Jackie Forrest is a senior director at IHS CERA. She leads the consultancy’s Oil Sands Dialogue.

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LEADING EDGE

Breaking Trail Imperial Oil looks to take water out of the oil sands extraction equation

Bruce March was speaking at an investor meeting

in Toronto this winter, when in the middle of a presentation that focused on Imperial Oil Ltd.’s reserve base and ambitious growth plans, he uttered the words “non-aqueous extraction.” “This technology would be a huge breakthrough from a number of perspectives,” the president, chairman and CEO of the Calgary-based company told the crowd. “Energy costs would be much lower because the need for hot water would be largely eliminated. And it would eliminate the need for fluid tailings ponds altogether. This is only one example of our company’s focus on responsible development of Canada’s oil sands, and how the ongoing use of technology to develop one of the world’s largest recoverable energy resources is being developed.” It was a bold statement. For the rub with the oil sands is that recovering a large portion of Alberta’s 169 billion barrels of reserves is no sure thing. Concern about water usage, carbon emissions, tailings ponds and how to remediate old strip mines means the Canadian Association of Petroleum Producers’ lofty projections of Canada going from producing 1.6 million barrels of oil sands per day in 2011 to 3.7 million barrels per day by 2025 could fail to materialize. The sector is under increasing pressure to use less water, emit less carbon dioxide and disturb less land as it goes about developing the oil sands. While environmentalists beg to differ, players in the oil sands recognize this and they are taking steps to do something about it. Enter Imperial Oil’s non-aqueous extraction (NAE) technology. It hasn’t even hit the pilot stage yet, but the technology has the potential to be a game changer for the industry. All oil sands

www.albertaoilMAGAZINE.com

mining operations use a version of the hot water separation process pioneered by Karl Clark at the Alberta Research Council in the 1920s to forcefully separate the bitumen from the sand and clay mixed with it. The process requires a lot of energy to heat the water, and the waste produced during the separation process must be dumped into large, unsightly and toxic tailings ponds. The NAE technology could do away with all that. In a nutshell, the process involves placing the mined sand in a container. Then an organic solvent and a very small amount of water are added to the mix creating a liquid slurry. The lid is then closed and the contents get spun around the container like wet clothes in a dryer. The rotation binds all the solids into ball-shaped forms. Then the bitumen and solvent are removed through a screening operation. A final process separates the bitumen and the solvent and the result is a bitumen product. The sand and clay that is left over can be placed back into the mine as dry tailings – eliminating the need for tailings ponds. In its 2011 annual report, Imperial says its NAE technology would reduce overall water use in the oil sands extraction process by more than 90 per cent. A group of sell-side analysts got an exclusive look at the technology’s potential during a January tour of Imperial’s Calgary research lab. A demonstration of NAE was given and analysts from Calgary-based investment boutique FirstEnergy Capital came away impressed. But its analysts recognize how far away the process is from being ready to use at oil sands mines. “This technology may not be ready for commercial implementation until the next decade. And if so, likely would not be applied at the Kearl [mine] project,” FirstEnergy analyst Michael Dunn wrote in a note to clients. “However, Imperial has other mining leases, and the intent is to move this process to commercialization for a mine that might get built in the 2020s.” >>

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of overall water use in the oil sands extraction process could be reduced through NAE technology

345,000

1969

barrels of oil per day is what Imperial Oil plans to produce by 2020

the year Imperial’s Dr. Roger Butler wrote the patent for his SAGD oil sands extraction process

Imperial intends to develop these mining leases. The company, established in 1880, produced an average of 255,000 barrels of oil per day (bpd) in 2011. By 2020, it plans to be pumping out 345,000 bpd – a 36 per cent increase in production. With 2.4 billion of Imperial’s 3.2 billion barrels of net proved reserves consisting of bitumen, it’s clear the oil sands will play a significant role in the company’s growth plans. Whether NAE technology will significantly aid that growth remains to be seen. Imperial Oil spokesperson Pius Rolheiser says a lot of work must be done before the company can start an NAE pilot project.

“This technology would be a huge breakthrough from a number of perspectives.” But this isn’t the first time the company faced long odds in the oil sands. In the 1960s the firm discovered a large oil deposit at Cold Lake, Alberta, but it had no economic way to produce it. That’s when Imperial’s Dr. Roger Butler came up with an idea: injecting steam into the reservoir could heat the oil, make it lighter and the heated oil would drain to the bottom of the chamber where it could be pumped to the surface using another well. Butler wrote the patent for his invention in 1969. Today it is known as the steam-assisted gravity drainage (SAGD) extraction method. Imperial clearly hopes it can hit another home run in the oil sands with its NAE research. “This could be a key instrument of growth,” Rolheiser says. “NAE would enable the oil sands to grow while allowing us to continue to improve on the job of managing the environment.” AO

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5 things

Don’t Fear the Reapers Foreign investment bodes well for Canada’s trade balance First it was Opti Canada Inc.,

scooped up by the China National Offshore Oil Company for $2.1 billion. Next was Daylight Energy Ltd., gobbled up by the China Petroleum and Petrochemical Corp. (known as Sinopec) for $2.2 billion. Then it was Athabasca Oil Sands Corp. (now called Athabasca Oil Corp.), whose MacKay River property was swallowed whole by PetroChina Ltd. The deals, a departure from a preference among national oil companies for minority stakes in Alberta companies, raise big questions about foreign invest-

1 Markets

Foreign investment helps forge trade relationships beyond the United States. Equity stakes in Canadian energy projects “will naturally lead to opportunities to export those resources to a more diverse customer base,” PwC says.

2 Prices

New trade relationships, in turn, mean better value for Canadian crude oil and natural gas. Robust global oil prices and oilindexed natural gas sales “provide a compelling opportunity to seek new export markets,” PwC says.

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3 Value Joint ventures with overseas firms help Canadian producers accelerate development of capital intensive resource plays and oil sands developments, allowing producers to extract value from unbooked resources.

ment in western Canadian energy assets, notes Reynold Tetzlaff, national energy leader at PricewaterhouseCoopers in Calgary. Could the growing footprint of Asia-Pacific capital provoke the sort of political backlash that scuttled a hostile bid for Potash Corp. of Saskatchewan? “There’s the potential,” Tetzlaff says. “If somebody took a run at Suncor, for example, what would happen? It would be interesting to see.” Below are a few reasons PwC thinks Canadians ought to welcome – not fear – foreign investment. AO

Jobs

The common critique of foreign takeovers – that they hollow out economies by exporting high-paying jobs – doesn’t necessarily apply to the oil and gas sector. Instead, investment tends to create jobs for new developments that might otherwise not have proceeded.

5 Transfers

It’s not just raw energy products that could lift Canada’s trade balance. Technology transfers embedded in joint venture agreements (think completions and advanced drilling techniques) “should be recognized as a major trade asset” in their own right, PwC notes.

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Greg boser, COO, ZEroCor Tubulars Inc.

Fresh Coat

A Calgary start-up looks to make a name for itself in the wellbore tubing business

People have been poking holes in the Western Canadian

Sedimentary Basin (WCSB) in search of hydrocarbons for more than a century. It’s a mature basin that few thought had much life left in it when it came to conventional oil. But in a 2011 reserves and supply/demand report, Alberta’s Energy Resources Conservation Board (ERCB) noted that exploratory and development drilling and enhanced oil recovery techniques had added 208 million barrels to the province’s established conventional crude oil reserves, which now stand at 1.5 billion barrels. The ERCB also said the 208 million barrels of oil reserves replaced 124 per cent of production in 2010. “This replacement level is one of the highest in recent years,” the report stated. That trend – wringing more oil from the WCSB – has intensified as companies look to take advantage of strong oil prices and protect themselves from rock-bottom natural gas prices.

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It’s almost a perfect storm for Greg Boser and Randy Cusson – two oil patch veterans who launched a new energy services company with those kinds of customers in mind. Boser and Cusson are COO and CEO, respectively, of Calgarybased zEroCor Tubulars Inc., a company they started in 2007 to develop products to protect wellbore tubing from erosion and corrosion. “We talked to operators about what they were doing to remediate this and we sensed there was a lot of frustration,” Boser says. The frustration comes because corrosion and erosion of wellbore tubing is so commonplace in the WCSB. To coax more black gold out of the basin’s reservoirs – where conventional extraction methods have only tapped 15 to 20 per cent of the oil in place – firms now pump carbon dioxide (C02), water or a combination of other fluids down a well

photograph bryce meyer

Experience, leadership, performance.

to increase pressure in the hydrocarbon zones and push the oil to desired areas where it can be pumped to the surface. However, C02, salt water and other contaminants that help get the oil, can also corrode the tubing in the wellbore. And as the pumps work to get the oil to surface, significant wear occurs on the inner tubing walls as well. This damage eventually forces the tubing to be replaced and production is stopped as rigs switch out the tubing. What Boser and Cusson’s company has developed are five products with complexsounding names like z-Ero 100 coated tubing and z-Cor Fusion Bonding Phenolic Epoxy. Yet the products do something pretty simple – protect the tubing from being scraped and corroded to failure. This allows the stuff to last longer, and it saves operators time and money.

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“The thrill is bringing new technology in that solves that problem.” Boser and Cusson have known each other since 1977. In the 1990s, Cusson owned an oilfield firefighting company, Key Safety Services, for 13 years before selling it in 2006. Cusson then took a year off before he and Boser teamed up to form zEroCor Tubulars. The first year-and-a-half of the firm’s existence was tied up in research and development efforts. But by January of 2009, they had two coating products to market. The firm now has five tubular products it sells and a sixth is in development. Fusson says they are looking at a 30 per cent increase in revenue this year and with interest in enhanced oil recovery and the oil sands greater than ever (the firm also caters to steam-assisted gravity drainage oil sands operators), they believe more growth is in the cards – although that isn’t what motivates them. “The thrill is bringing new technology in that solves that problem for an operator,” Boser says. AO

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the suite life

Gender Shift

Why populating your board with women can pay dividends By Anthony A. Davis Here are some numbers that

should make the business world hang its head in embarrassment: 46.2 per cent of Standard & Poor’s (S & P) 500 companies have no women – zippo – on their boards. And while Canadian businesses might pat themselves on the back for making strides in gender equality, a step into some boardrooms is like a step into a cave room with oak paneling. A 2011 Catalyst census of the S & P 500 found women currently hold just 14.5 per cent of available director seats; a mere 0.5 per cent increase during the previous two years. At that rate, it would take 71 years – until 2083 – to reach gender parity in Canadian boardrooms. By then, there might be a few androids at the table, too. Yet, here’s a fact that should make firms sit up and beg for more women board directors. According to some pretty compelling research, companies that have them are, in just about any corporate financial measurement you can think of, kicking the bottom-line butts of those that don’t. It might be tempting for Deborah Gillis to give a nyah-nyah to all those Canadian boardrooms that remain menonly bastions, but she’s too nice for that. Gillis is the senior vice-president of membership and global operations for New York City-based Catalyst, an organization that has had the backs of women in the workplace for decades. The firm’s research on corporate bottom-line performance and female representation on boards is

www.albertaoilMAGAZINE.com

particularly noteworthy. As Gillis puts it, “the data is quite compelling.” Take the numbers Catalyst crunched on Fortune 500 companies from 2004 to 2008. On average, companies with the highest representation of women (three or more board members in at least four of the five years of the study) had returns on sales that were 84-per-cent higher than those who had the lowest average of female board members. And return on invested equity was 60-per-cent better for the female-friendly corporations compared to those with dudes-only boards.

What the study doesn’t examine is causation. Why do companies with more female directors seem to outperform those without them? Gillis has some educated guesses. “These companies are essentially playing with the full deck of talent that is available to drive a business. It’s tapping into the very best and brightest that’s out there.” Not just half of the very best and brightest out there. And, Gillis adds, since many companies sell products and services to women, as well as men, “Having an understanding of the customers and consumers you have

is very critical to most businesses. Women can help with that.” In the oil patch, according to Corporate Knights’ 5th Annual Diversity Report, a 2011 study of Canadian companies on the S & P/TSX, Imperial Oil Ltd. tops the list as the energy company with the most gender diversity in the boardroom. It was 10th overall out of 50 corporations when looking at all industries. Two of its seven directors are women. That’s 29 per cent. Plaudits to Imperial, but that’s as good as it gets in the patch. “Looking at mining, quarrying, oil and gas extraction,” Gillis says, “women hold 5.9 per cent of board seats. [That’s] certainly lower than the S & P 500 average. So I think this is an issue the industry needs to focus on, to recognize the importance of tapping into and leveraging talent, in an industry that is growing and clearly so important to the Canadian economy.” You’d get no argument from Sheelagh Whittaker, one of the two women on Imperial Oil’s board, along with Krystyna Hoeg. The former CEO of Canadian Satellite Communications, and later EDS Canada, Whittaker also serves on the board of Standard Life plc, and was an RBC director. But she has a different take on the business case for more female board members in the corporate world. “Having women on boards is morally required. It’s a virtue, it’s justice.” Why would companies, Whittaker wonders, continue to fight progress and tick off consumers to keep women out of the boardroom? “People ought to do the right thing, and the right thing is to have women represented on boards. You don’t need a business case for that.” AO Anthony A. Davis is a Calgary-based freelance writer who has a written on a range of subjects around the world.

illustration kaley mckean

the

LIVING LARGE

Canada might not have reached “energy superpower” status yet, but within its own borders, it’s clear the oil and gas industry looms very large. A quick glance through this year’s list of the top-performing oil and gas and energy service firms illustrates the wealth this surging sector is creating in Canada. Despite concerns about a lack of access to new markets and the environmental footprint of hydrocarbon extraction, 2011 was another year of growth. The trick now is how to keep the good times rolling. This package was developed in partnership with Deloitte. The 100 + Energy Service 50 luncheon held on May 31 in Calgary featuring keynote speaker Jack Gerard was presented by Alberta Oil, ATB Corporate Financial Services, Deloitte, the University of Calgary’s Haskayne School of Business, and Rogers.

Energy Service

40 Turbulent Times

Price discounts, pipeline bottlenecks and labor woes haven’t slowed down growth in the oil patch

44 The 100 + Energy Service 50

A look at Canada’s top-performing oil and gas and energy service companies

54 follow the leader

Why a potential regime change in oil-rich Venezuela matters to Alberta

For more information on The 100 + Energy Service 50, go to www.100.albertaoilmagazine.com

june 2012

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the100

+ ENERGY SERVICE 50

Pipeline bottlenecks, price discounts, labor shortages – none of it crimped the oil patch’s growth in 2011

Turbulent

Times

By DR. GEOFF HILL / ILlustration KYLE METCALF

It’s

probably more than cliché to refer to a year just passed, whatever the context, as having been tumultuous or volatile or, simply, intense. But in the Canadian oil and gas industry, the past 12 months have been all of that. A lot of the volatility hangs on the U.S. government’s decision in January not to approve the Keystone XL pipeline, arguing that the project, as proposed at the time, was not in the U.S. national interest. It’s not that this decision was entirely unexpected in an election year, but given that Keystone XL is in Canada’s national interest, we felt it. It hit us where we live, as the saying goes. In May, Keystone XL proponent TransCanada Corp. reapplied to the U.S. State Department for a presidential

permit to build this pipeline, meant to ship Alberta oil sands crude to Gulf Coast refineries. But until the permit is granted, the future of the project is uncertain. That’s not good for a Canadian oil patch that will continue to feel the effects of this uncertainty throughout 2012. For Canada, Keystone XL isn’t just about the economic boost from the construction, operation and maintenance jobs that will come with it, it’s the boost from our ability to continue to grow production with the certainty that we will be able to get it to a market where that crude won’t experience discounted prices from being landlocked, and all the jobs that are affected by that. There are thousands of jobs affected by production growth in Canada. According to the Canadian Association of Petroleum Producers, the oil and gas industry in Canada “supports” 550,000 jobs across the country. The oil sands alone, says the Canadian Energy Research Institute (CERI), will create 905,000 new jobs by 2035 – provided there is a market for the expansion of production assumed by those estimates.

june 2012

the100

+ ENERGY SERVICE 50

eaving aside the political implications, the Keystone XL decision also triggered a renewal of discussion around the Northern Gateway pipeline and the opening of direct trade with Asia via the West Coast. As near and dear as the United States surely is to Canada as an oil and gas export market, it is now absolutely clear that it is not in our national interest to be dependent on a single country’s market for our resources. For this reason, more than probably any other, calls were also renewed this year for some kind of national energy strategy. While the Keystone XL, and the larger issue of access to new markets, looms large over the Canadian oil and gas industry, as the results of The 100 + Energy Service 50 lists show, 2011 was a year of growth. With a large resource base and the world’s growing energy needs, Canada’s oil and gas are prized commodities. But there are a few issues that will determine what production heights the industry can reach in the near-term.

ne of these is low natural gas prices, driven by excess production in the U.S. and the lack of infrastructure to transport that gas offshore until liquefied natural gas facilities are built. Gas producers are suffering, even if gas consumers such as SAGD oil sands operators are not. We’re keeping our focus on the regulatory environment in the U.S., specifically around hydraulic fracturing to see whether production might slow to the point that prices begin to rise again. Another key issue is foreign investment in the oil patch, particularly from Asia. Direct Asian investment in the sector nearly doubled from $5.9 billion in 2009 to $10.9 billion in 2010. This has been mostly a win-win situation for Canada and Asian national oil companies: they’ve been able to tap into our reserves and technology infrastructure while we’ve relied on them to some extent for needed capital, especially through the recent recession. But with Canada’s oil and gas effectively trapped in North America, it’s especially hard to predict the long game around this activity generally – like a chess match where each player begins the game missing a different piece. A curtailing of Asian investment could lead to reduced production growth, potentially hastening another economic bust. All of this remains overshadowed by another big concern – labor shortages and debate around the environmental and social sustainability of oil and gas development. Though the 2008 recession brought some relief to these pressures, the underlying challenges were not solved and threaten to return worse than before.

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As noted, though some studies predict huge numbers for production and job growth, others suggest we don’t have enough of the right kinds of people and skills to grow production. The Current and Short-Term Workforce Trends report published by the Petroleum Human Resources Council of Canada and Deloitte cites “attraction and retention of workers to hard-to-recruit locations” as the number one workforce challenge facing the petroleum industry. The report estimates that, in addition to 90,000 new oil patch workers, nearly 40,000 workers will be needed by 2020 just to replace those who retire. Nobody is entirely sure where they are all going to come from. Environmental and social sustainability issues pose significant challenges as well. These challenges tend to be rooted more in negotiation over terms and the limits of what’s possible (today versus tomorrow) than in some basic indeterminacy of how to solve them or whether they should be solved at all. These challenges will not be easy to overcome, but we are already seeing significant progress. The public at large is concerned, to varying degrees, about the general impact of oil and gas production on the environment – carbon dioxide emissions, water use, land and animal disturbance, and more. Industry is equally concerned with the economic value of its activity and how to strike a balance between growth and stewardship. Deloitte advocates continued and genuine dialogue on these issues specifically, for the benefit of industry and all concerned stakeholders.

s we look back on 2011, from our perspective industry has generally responded to these and other business pressures by turning to innovation and collaboration. We are seeing immigration policies aimed at mitigating labor issues by putting the right people in the right places faster. There is technology innovation and investment, at both the industry and government levels, aimed at actively addressing key areas of corporate responsibility. The federal government’s commitment to regulatory streamlining, simplifying and expediting application and project reviews in order to progress resource and market development in an orderly and compliant fashion, is also encouraging. More specifically, a number of developments involving new associations and partnerships this year speak to the new levels of trust industry players are putting in one another to drive progress for all stakeholders. Not the least of which, on this front, is the newest kid on the block – Canada’s Oil Sands Innovation Alliance (COSIA), announced in March, which will focus on “accelerating the pace of improvement in environmental performance in Canada’s oil sands through collaborative action and innovation.” The good news is companies continue to grow, as this year’s data clearly shows. Though the ranking of the top 100 Canadian oil and gas producers itself has changed little (this is the first year Alberta Oil has ranked energy service companies), relatively few companies actually experienced decreases year over year. Of the top 20 companies on the list, only one has seen a decrease in revenues while seven have seen decreases in oil production and a couple more than that produced less natural gas. It is a picture of the normal ebb and flow of business and life – no significant revolutions, just natural evolution. AO

Dr. Geoff Hill is leader of Deloitte Canada’s national oil and gas sector group and a partner in its Calgary office. He can be reached at gehill@deloitte.ca

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Now, who are you going to trust your business with?

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the100

Compiled with the assistance of

+ ENERGY SERVICE 50

revenue

oil production

net income

canadian public oil and gas producers by revenue

2011 revenue ($m)

2011 rank

2010 revenue ($m)

2010 rank

2011 net income ($m)

2011 rank

2010 net income ($m)

2010 rank

2011 oil production (bpd)*

Suncor Energy Inc. Imperial Oil Ltd. Husky Energy Inc. Cenovus Energy Inc. Canadian Natural Resources Ltd. Encana Corp. † Talisman Energy Inc. Nexen Inc. Harvest Operations Corp. Canadian Oil Sands Ltd. Pacific Rubiales Energy Corp. † Penn West Petroleum Ltd. Crescent Point Energy Corp. Petrominerales Ltd. † ARC Resources Ltd. Pengrowth Energy Corp. Enerplus Corporation Baytex Energy Corp. PetroBakken Energy Ltd. Petrobank Energy and Resources Ltd. AvenEx Energy Corp. MEG Energy Corp. Vermilion Energy Inc. Bonavista Energy Corp. Connacher Oil & Gas Ltd. Gran Tierra Energy Inc. † NAL Energy Corp. Niko Resources Ltd.** Progress Energy Resources Corp. Peyto Exploration and Development Corp. Trilogy Energy Corp. NuVista Energy Ltd. Tourmaline Oil Corp. Advantage Oil & Gas Ltd. Legacy Oil + Gas Inc. Crew Energy Inc. Bankers Petroleum Ltd. † C&C Energia Ltd. † TransGlobe Energy Corp. † Birchcliff Energy Ltd. Perpetual Energy Inc. Paramount Resources Ltd. Chinook Energy Inc. Celtic Exploration Ltd. Pace Oil and Gas Ltd. Fairborne Energy Ltd. Bellatrix Exploration Ltd. Guide Exploration Ltd. Zargon Oil and Gas Ltd. Parex Resources Inc.

39,337 30,474 23,364 15,696 13,792 8,376 8,106 6,169 4,331 3,875 3,345 3,006 1,816 1,244 1,219 1,176 1,118 1,097 1,010 1,010 1,001 990 977 883 873 590 442 428 414 346 342 326 319 302 301 296 273 257 245 235 227 220 211 199 194 185 165 159 158 156

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50

35,220 24,946 18,178 12,973 14,322 8,870 6,912 5,411 3,802 3,460 1,662 3,054 1,536 1,049 1,214 1,353 1,327 1,005 1,009 1,009 626 738 728 939 574 374 498 348 443 319 291 373 226 319 215 206 170 156 269 190 260 184 115 222 172 235 118 208 179 138

1 2 3 5 4 6 7 8 9 10 12 11 13 17 16 14 15 20 18 18 25 22 23 21 26 29 27 31 28 32 34 30 39 33 42 44 49 50 35 45 36 46 58 40 48 38 56 46 47 52

4,304 3,371 2,224 1,478 2,643 127 768 697 -105 1,144 548 638 201 488 287 85 109 217 209 -8 -3 64 143 137 -114 126 -11 118 148 128 17 -144 44 -153 19 -130 36 31 81 34 -96 -232 -64 -28 17 -74 -6 -213 10 55

1 2 4 5 3 20 7 8 120 6 10 9 15 11 12 24 23 13 14 84 70 26 17 18 121 21 89 22 16 19 39 124 28 125 36 123 30 32 25 31 119 127 112 106 41 113 77 126 48 42

3,571 2,210 1,173 993 1,697 1,499 648 1,197 -45 886 218 226 20 240 261 230 127 178 48 116 -2 40 111 202 -39 37 32 119 -62 122 13 -14 15 -44 -5 -17 14 78 38 6 -29 -123 -45 -7 -397 -16 -28 -39 9 -13

1 2 6 7 3 4 9 5 119 8 14 13 31 11 10 12 17 16 24 20 60 25 21 15 116 27 29 19 123 18 34 98 32 118 78 103 33 22 26 37 111 125 119 88 127 101 110 116 36 97

472,721 255,000 211,300 134,239 389,053 24,000 178,000 167,300 38,434 106,015 90,013 103,208 66,604 38,378 31,654 37,539 33,487 42,021 35,156 35,156 2,256 26,605 22,334 26,758 13,806 17,408 13,288 1,930 5,710 3,856 8,046 8,180 3,346 6,230 10,390 10,993 12,784 8,455 12,132 4,450 2,027 3,833 5,224 3,789 6,245 3,182 4,540 4,070 5,468 5,345

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2010 oil 2011 production (bpd)* rank 1 3 4 7 2 22 5 6 13 8 10 9 11 14 19 15 18 12 16 16 67 21 23 20 25 24 26 73 38 52 33 32 57 37 30 29 27 31 28 49 72 54 44 55 36 58 47 51 40 43

528,100 247,000 202,600 129,187 424,985 22,787 189,000 202,800 35,917 107,280 58,055 98,966 55,070 37,027 31,586 38,143 35,024 35,124 35,109 35,109 1,646 21,257 19,941 26,182 9,182 14,325 14,293 2,941 5,322 3,389 4,642 7,700 1,922 7,202 7,533 5,410 9,597 5,842 9,960 3,583 1,245 3,417 3,080 4,070 4,289 3,969 2,550 4,450 5,645 77

2010 rank 1 3 5 7 2 21 6 4 14 8 10 9 11 13 19 12 18 15 16 16 64 22 23 20 29 25 26 53 37 51 41 30 60 32 31 36 28 34 27 48 70 50 52 44 43 45 56 42 35 108

natural gas production 2011 natural gas production (mcfpd)

Taking Stock

2010 natural 2011 gas production 2010 rank (mcfpd) rank

439 254 607 656 1,257 3,333 1,491 239 112 0 57 359 43 0 311 219 251 49 35 35 17 0 77 255 4 0 90 224 226 190 120 104 166 130 14 69 0 0 0 82 130 82 56 75 47 69 44 48 22 0

6 10 5 4 3 1 2 12 21 75 31 7 39 75 8 15 11 33 42 42 51 75 26 9 65 75 23 14 13 16 20 22 17 18 56 28 75 75 75 24 18 24 32 27 36 28 38 34 48 75

522 280 507 737 1,243 3,184 1,367 260 81 0 60 394 39 0 254 219 289 55 39 39 14 0 73 240 9 0 93 283 214 122 109 124 96 102 7 50 0 0 0 57 145 58 40 79 43 67 36 62 25 0

5 10 6 4 3 1 2 11 25 104 30 7 38 104 12 14 8 33 38 38 55 104 27 13 63 104 23 9 15 19 20 18 22 21 68 34 104 104 104 32 16 31 36 26 35 28 43 29 47 104

In Canada’s oil patch, the industry’s giants did the heavy lifting with financial and resource outputs in 2011

Oil Top 10 SUNCOR ENERGY INC.

The Calgary-based firm’s net income increased in 2011 by

$733 million

Progress Energy Resources Corp.

Suncor Energy Inc. Canadian Natural Resources Ltd. Imperial Oil Ltd. Husky Energy Inc. Talisman Energy Inc. Nexen Inc. Cenovus Energy Inc. Canadian Oil Sands Ltd. Penn West Petroleum Ltd. Pacific Rubiales Energy Corp. TOTALS:

Natural Gas Top 10 Encana Corp. Talisman Energy Inc. Canadian Natural Resources Ltd. Cenovus Energy Inc. Husky Energy Inc. Suncor Energy Inc. Penn West Petroleum Ltd. ARC Resources Ltd. Bonavista Energy Corp. Imperial Oil Ltd. TOTALS:

Earnings Top 10

Petronas acquired a 50 % stake in some of Progress’s Montney gas assets for

$1.07 billion

Suncor Energy Inc. Imperial Oil Ltd. Canadian Natural Resources Ltd. Husky Energy Inc. Cenovus Energy Inc. Canadian Oil Sands Ltd. Talisman Energy Inc. Nexen Inc. Penn West Petroleum Ltd. Pacific Rubiales Energy Corp. TOTALS:

2011 rank 1 2 3 4 5 6 7 8 9 10

2011 oil production (bpd)* 472,215 389,053 255,000 211,300 178,000 167,300 134,239 106,015 103,208 90,013 2,106,343

2010 rank 1 2 3 5 6 4 7 8 9 10

2010 oil production (bpd)* 528,100 424,985 247,000 202,600 189,000 202,800 129,187 107,280 98,966 58,033 2,187,951

2011 rank 1 2 3 4 5 6 7 8 9 10

2011 natural gas production (mcfpd) 3,333 1,491 1,257 656 607 439 359 311 255 254 8.962

2010 rank 1 2 3 4 6 5 7 12 13 10

2010 natural gas production (mcfpd) 3,184 1,367 1,243 737 507 522 394 254 240 280 8,728

2011 rank

2011 net income ($millions)

2010 rank

2010 net income ($millions)

1 2 3 4 5 6 7 8 9 10

4,304 3,371 2,643 2,224 1,478 1,144 766 697 638 554 17,819

1 2 3 6 7 8 9 5 13 14

3,571 2,210 1,697 1,173 993 886 648 1,197 226 218 12,819

$m = Millions • bpd = Barrels Per Day • mcfpd = Million Cubic Feet Per Day • NR = was not ranked last year * Includes conventional oil, bitumen, synthetic crude, and natural gas liquids ** nine months ending December 31

Illustration KYLE METCALF

june 2012

the100

Compiled with the assistance of

+ ENERGY SERVICE 50

revenue canadian public oil and gas producers by revenue

2011 revenue ($m)

Freehold Royalties Ltd. Angle Energy Inc. Bonterra Energy Corp. Compton Petroleum Corp. BlackPearl Resources Inc. Equal Energy Ltd. WestFire Energy Ltd. Whitecap Resources Inc. Twin Butte Energy Ltd. Vero Energy Inc. Delphi Energy Corp. NuLoch Resources Inc.* Anderson Energy Ltd. Canacol Energy Ltd. Cequence Energy Ltd. Midway Energy Ltd. Arcan Resources Ltd. Emerge Oil & Gas Inc. Wild Stream Exploration Ltd. Pan Orient Energy Corp. Renegade Petroleum Ltd. Painted Pony Petroleum Ltd. Terra Energy Corp. Winstar Resources Ltd. Rock Energy Inc. Crocotta Energy Ltd. Arsenal Energy Inc. Calvalley Petroleum Inc. Insignia Energy Ltd. RMP Energy Ltd. Open Range Energy Corp. Ivanhoe Energy Inc. Parallel Energy Trust Dundee Energy Limited (Eurogas Corp.) Second Wave Petroleum Inc. Artek Exploration Ltd. Sonde Resources Corp. Eagle Energy Trust Waldron Energy Corp. Kulczyk Oil Ventures DeeThree Exploration Ltd. Yoho Resources Ltd. Exall Energy Corp. Palliser Oil & Gas Corp. Seaview Energy Inc.** TriOil Resources Ltd. Corridor Resources Inc. Sure Energy Inc. Reliable Energy Ltd. Strategic Oil and Gas Ltd. TOTALS

154 148 145 142 134 128 126 120 118 112 106 106 104 91 87 85 85 81 70 69 66 65 60 52 52 49 47 46 44 43 40 37 37 36 36 36 35 32 29 28 27 26 25 25 24 23 23 23 21 19

(continued)

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2011 rank

2010 revenue ($m)

51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 184,590

138 121 119 216 143 144 43 0 102 109 117 19 86 16 51 40 56 110 45 103 29 58 80 53 63 35 44 64 38 0 48 22 0 19 26 27 37 1 24 7 7 26 22 13 35 20 30 13 9 6 161,835

oil production

net income 2010 rank 52 53 54 40 51 50 74 124 61 59 56 91 62 94 69 75 67 58 71 60 82 66 63 68 65 78 73 64 76 124 70 87 124 84 91 83 77 119 NR 108 108 84 87 98 78 90 81 98 105 112

2011 net income ($m) 55 11 44 17 19 -14 -53 26 -19 -75 12 -77 -22 -11 -20 14 -1 15 15 24 -3 7 -7 7 -7 -6 -3 21 -12 -75 -3 -25 -40 -1 -9 -17 -41 -1 -14 -17 -13 -4 7 -5 -48 -15 -80 -1 0 -25 18,860

2011 rank 27 47 29 40 38 92 111 33 98 116 46 117 103 88 102 45 63 44 43 34 69 52 79 50 80 75 68 35 90 114 71 105 107 65 87 96 108 64 93 95 91 73 51 74 109 94 118 62 57 104

2010 net income ($m) 36 -5 50 -331 -31 -35 -6 0 -1 -4 -1 -3 -36 -22 -15 -4 -5 -27 4 21 -8 2 -9 2 -4 -7 -8 11 -14 0 -4 -29 0 -4 -7 -5 -98 -3 0 -18 -7 -3 3 -3 -5 -10 -9 -3 0 5 14,800

2010 rank 28 78 23 126 113 114 85 45 55 71 53 67 115 106 100 71 78 108 40 30 91 43 94 43 71 88 91 35 98 45 71 111 45 71 87 78 124 67 45 104 88 65 42 63 78 96 94 64 51 38

2011 oil production (bpd)* 4,697 5,409 4,461 2,191 7,460 5,391 3,839 3,588 4,669 2,226 2,538 2,380 2,422 7,051 1,039 2,707 3,097 5,563 4,073 2,030 2,392 1,622 1,169 1,215 2,294 1,214 1,824 2,081 902 877 323 967 2,355 718 1,110 997 765 1,376 630 55 698 569 970 1,319 380 663 11 611 739 659 2,860,294

2010 oil 2011 production (bpd)* rank 45 41 48 69 34 42 53 56 46 68 61 64 62 35 82 60 59 39 50 71 63 75 80 78 66 79 74 70 86 87 102 85 65 92 81 83 90 76 96 118 93 98 84 77 100 94 120 97 91 95

4,704 3,535 3,875 2,791 6,375 4,972 1,228 0 2,899 1,867 1,617 620 1,379 822 625 1,184 1,983 4,805 1,809 3,884 1,045 1,729 1,496 1,579 2,376 746 1,588 2,256 695 0 349 788 0 688 871 584 648 726 466 23 17 398 759 567 370 534 0 236 327 221 2,836,120

2010 rank 40 49 47 55 33 38 71 117 54 61 65 85 69 75 84 72 59 39 62 46 73 63 68 67 57 79 66 58 81 117 93 77 117 82 74 86 83 80 89 112 115 89 78 87 91 88 117 98 95 99

natural gas production 2011 natural gas production (mcfpd) 17 47 11 67 1 29 12 12 18 42 38 19 32 0 48 7 1 1 2 0 1 16 30 3 5 15 2 0 15 16 24 0 7 11 3 8 12 0 12 9 7 11 1 0 12 4 12 4 0 2 12,732

Leap Years

2010 natural 2011 gas production 2010 rank (mcfpd) rank 51 36 58 30 73 46 57 57 50 40 41 49 44 75 34 61 73 73 70 75 73 53 45 68 64 55 70 75 55 53 47 75 61 58 68 60 57 75 57 59 61 58 82 75 57 65 57 65 75 70

17 34 11 88 3 25 8 0 22 40 39 2 37 0 23 6 2 1 1 0 0 7 32 1 7 10 3 0 13 0 21 0 0 10 3 7 13 0 15 10 4 4 11 15 0 4 13 4 0 1 12,259

53 44 59 24 82 47 65 104 51 36 38 88 42 104 50 73 89 95 90 104 104 68 45 90 68 61 82 104 56 104 52 104 104 61 82 68 56 104 55 76 76 59 95 55 54 75 56 76 104 97

Gains in production and profit were not exclusively the domain of industry’s titans in 2011

Net Income CENOVUS ENERGY INC.

The oil sands producer’s capital investment in 2011 was

$2.6 billion

CANADA

Imperial Oil Ltd. Husky Energy Inc. Canadian Natural Resources Ltd. Suncor Energy Inc. Cenovus Energy Inc. Penn West Petroleum Ltd. Pacific Rubiales Energy Corp. Canadian Oil Sands Ltd. Progress Energy Resources Corp. Crescent Point Energy Corp.

Oil Production Pacific Rubiales Energy Corp. Crescent Point Energy Corp. Husky Energy Inc. Imperial Oil Ltd. Baytex Energy Corp. Canacol Energy Ltd. MEG Energy Corp. Cenovus Energy Inc. Penn West Petroleum Ltd. Connacher Oil & Gas Ltd.

Natural Gas Production

2011 Canadian light and heavy oil exports, in barrels per day, were

2.2 million

2011 net income ($millions)

2010 net income ($millions)

Increase

3,371 2,224 2,643 4,304 1,428 638 554 1,144 148 201

2,210 1,173 1,697 3,571 993 226 218 886 -62 20

1,161 1,051 946 733 435 412 336 258 210 181

2011 rank

2011 production (bpd)*

2010 production (bpd)*

Increase

1 2 3 4 5 6 7 8 9 10

90,013 66,604 211,300 255,000 42,021 7,051 26,605 134,239 103,708 13,806

58,055 55,070 202,600 247,000 35,124 822 21,257 129,187 98,966 9,182

31,958 11,534 8,700 8,000 6,897 6,229 5,348 5,052 4,742 4,624

2011 production (mcfpd)

2010 production (mcfpd)

Increase

3,333 1,491 607 166 190 311 130 82 255 47

3,184 1,367 507 96 122 254 102 57 240 34

149 124 100 70 68 57 28 25 15 13

2011 rank 1 2 3 4 5 6 7 8 9 10

2011 rank Encana Corp. 1 Talisman Energy Inc. 2 Husky Energy Inc. 3 Tourmaline Oil Corp. 4 Peyto Exploration & Development Corp. 5 ARC Resources Ltd. 6 Advantage Oil & Gas Ltd. 7 Birchcliff Energy Ltd. 8 Bonavista Energy Corp. 9 Angle Energy Inc. 10

$m = Millions • bpd = Barrels Per Day • mcfpd = Million Cubic Feet Per Day * Includes conventional oil, bitumen, synthetic crude, and natural gas liquids ** nine months ending December 31 † - Report in U.S. Dollars. An average conversion rate from U.S. to Canadian Dollars of 0.989 was used. * Now Williston Hunter Canada Inc. ** Now Charger Energy

Illustration KYLE METCALF

june 2012

the100

Compiled with the assistance of

+ ENERGY SERVICE 50

revenue energy service 50 by revenue Gibson Energy Inc. Parkland Fuel Corporation Keyera Corp. Trican Well Service Ltd. Precision Drilling Corp. Pembina Pipeline Corp. Flint Energy Services Ltd. (Bought by URS Corp.) Calfrac Well Services Ltd. Enerflex Ltd. Clean Harbors Industrial Services Canada, Inc. Trinidad Drilling Ltd. North American Energy Partners Inc. Newalta Corp. Savanna Energy Services Corp. Secure Energy Services Inc. Canadian Energy Services & Technology Corp. Canyon Services Group Inc. Total Energy Services Inc. Essential Energy Services Western Energy Services Corp. PHX Energy Services Corp. Pure Energy Services Ltd. Black Diamond Group Ltd. Akita Drilling Petrowest Corporation Strad Energy Services Ltd. Tuscany International Drilling Inc. CanElson Drilling Inc. GasFrac Energy Services Inc. Logan International Inc. Macro Enterprises Inc. High Arctic Energy Services Inc. Calmena Energy Services Inc. Xtreme Coil Drilling Corp. Camex Energy Services Bonnett’s Energy Corp. Cordy Oilfield Services Inc. Integrated Production Services IROC Energy Services Corp. Arnett & Burgess Pipeliners Enseco Energy Services Co. Warrior Manufacturing Services Ltd. Ketek Group Inc. Pulse Seismic Inc. Technicoil Corporation Leader Energy Services Dalmac Energy Inc. Winalta Inc. Drilformance Enterprise Oilfield Group Inc. TOTALS

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2011 revenue ($m) 5,072 3,981 2,569 2,310 1,951 1,677 1,616 1,537 1,227 825 797 724 683 611 551 459 372 332 317 263 260 246 242 200 190 188 186 185 161 134 129 127 125 104 100 99 94 87 86 65 54 44 38 36 35 34 25 22 19 18 31,207

2011 rank 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50

2011 income ($m) -63 44 135 335 194 166 24 187 -7 126 77 -4 34 46 22 42 95 69 31 65 18 22 41 23 -28 -9 -26 34 -3 15 6 18 -9 0 0 13 -2 0 12 0 2 0 0 5 4 2 2 7 0 0 1,765

2011 rank 40 12 5 1 2 4 17 3 35 6 8 34 15 11 19 13 7 9 16 10 21 19 14 18 39 36 38 15 33 23 25 21 36 31 31 24 32 31 25 31 29 31 31 26 27 29 29 24 31 31

top 5 americanbased companies Schlumberger Baker Hughes Inc. Spectra Energy Corp. Forbes Energy Services Ltd. Tesco Corporation

2011 rank

2011 revenue ($M)

2011 income ($M)

1 2 3 4 5

39,540 19,831 5,351 441 513

4,997 1,743 1,282 (12) 27

65,676

8,037

TOTALS:

In Brief This is the first year Alberta Oil has compiled a list of some of Canada’s top-performing energy service companies. We’ve ranked the firms who populate this sector by revenue and net income because – unlike explorers and producers – they don’t produce oil and gas. But there are noteworthy financial details contained in the annual reports of these companies that speak to the growth the sector is experiencing that couldn’t be included in this year’s top 50 list. What follows are a few of those details culled from the financials of some select firms. ■

■

GibsonEnergy Inc. acquired Palko Environmental Ltd. in December, 2011 for $62.7 million. Newalta’s net earnings in 2011 rose to $33.6 million from $16.1 million in 2010.

PRECISION DRILLING

WesternEnergy Services Corp.’s EBITDA increased by 502 per cent to $99.3 million in 2011 compared to $16.5 million in 2010. Bonnett’sEnergy Corp. was able to reduce its debt in 2011 by $12.6 million to $18.6 million. Leader Energy Services saw its revenues increase by 32 per cent in 2011 − $34.2 million in 2011 compared to $26.5 million in 2010. WinaltaInc. generated cash flow of $9.8 million from continuing operations in 2011. Essential Energy Services’ EBITDA increased to $72 million in 2011 from $29 million in 2010.

Capital spending in 2011 was

$726 million

$m = Millions * Includes conventional oil, bitumen, synthetic crude, and natural gas liquids ** nine months ending December 31. EBITDA stands for earnings before interest, tax, depreciation and amorization Alberta Oil’s 100 list was compiled by reviewing the annual reports and financial statements of 127 Canadian oil and gas producers. Of those companies, the ones with the best gross revenues were included in the list. Where gross revenues of the listed companies are the same, ties were broken by net income. Please note that in the net income, oil production and natural gas production categories, the rankings reflect where each company stood in comparison to all 127 companies surveyed. The energy service 50 list was compiled by reviewing the annual reports and financial statements of 77 companies with Canadian office. Of those companies, the ones with the largest gross revenues were included in the list.

To learn more about the criteria used to select the companies that made The 100 + Energy Service 50 list, log on to www.100.albertaoilmagazine.com

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the100

+ ENERGY SERVICE 50

mighty

Small but

Western

Canada’s vibrant energy service sector is populated by hundreds of companies. Some of them are large, publicly-traded firms − like Gibson Energy and Schlumberger − but many more are private “mom and pop” shops, with a handful of employees and lean and mean operations. What follows is a snapshot of five private energy service firms who didn’t make our 100 + Energy Service 50 lists, but who punch above their weight on the oilfield frontlines.

Oil Boss Rentals Inc.

Caliber Planning

Goliath Snubbing Ltd.

Location: Rocky Mountain House, Alberta Management: Gerry Casorso - president and CEO Employees: 8 (full time) Line of work: Provide logistics and rental equipment to the drilling, completions and services sector. Business in brief: Renting out everything from roughneck trailers to rig mats, the company bills itself as a one-stop rental and oilfield services outfit. Oil Boss Rentals has expanded its operations into the oil sands, but the company’s motto hasn’t changed. “We may not be the largest company, but we can honestly say that we give 100 per cent for our costumers every day,” Casorso says.

Location: Calgary Management: Tony Messer president and CEO Employees: 24 (full time) Line of work: Provide emergency response planning and security services. Business in brief: Caliber Planning expanded into the Northwest Territories market in 2011 and it’s expanded its health, safety and environment services as well. The company says it is now open to a partnership, joint venture or acquisition of a similar or complementary service provider. “Our people go above and beyond to serve our clients needs,” Messer says.

Location: Red Deer, Alberta Management: Trevor Sopracolle and Garrett Radchenko Employees: 10 (full time) Line of work: Well services snubbing company. Business in brief: Sopracolle and Radchenko boast 23 years combined snubbing experience. Focused on the Alberta market, in 2011 Goliath bought a new snubbing rig and expanded its operations to the Grande Prairie area. “We have a very strong company. We have the best equipment/ name and guys working for us. We started at the toughest time, too. Just before the recession and built this company up to where it is now,” Sopracolle says.

www.albertaoilMAGAZINE.com

K.C. Seals Inc. Location: Calgary Management: Alan Stiff - president Employees: 9 (full time) Line of work: Manufacture seals and gaskets for the oil and gas industry. Business in brief: K.C. Seals Inc. creates customized engineering seals for not only the oil and gas sector, but a broad range of industries. The company focuses on quality and research and development, and considers itself a leader in seal design and development.

Klaus Services Ltd. Location: Sherwood Park Management: Larry Klaus - president Employees: 51 (full time) Line of work: Design and manufacture compressor valves and other components. Business in brief: Klaus Services Ltd. has three locations in Alberta and after years of focusing on northern Alberta, it offers its services in southern Alberta. In 2011, the company expanded the size of its Calgary facility and added new product lines.

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the100

+ ENERGY SERVICE 50

Big Bites

Little Bites

Headline deals in the oil patch Mitsubishi Corp.

Encana Corp.

Type: 40% share in Cutbank Ridge property Value: $2.9 billion

China National Petroleum Corp.

Buyer: China Petroleum & Chemical Corp. Target: Daylight Energy Ltd. Type: Outright takeover Value: $2.2 billion

Buyer: Cnooc Ltd. Target: Opti Canada Inc. Type: Outright takeover Value: $2.1 billion

Shell Canada Ltd.

Type: 20% share in Groundbirch shale gas property Value: Unknown

Petronas

Progress Energy Resources Corp.

Type: 50% share in Montney shale gas property Value: $1.07 billion

Sasol Ltd.

Talisman Energy Inc.

Type: 50% share of Montney shale gas property Value: $1.03 billion Buyer: Pengrowth Energy Corp. Target: NAL Energy Corp. Type: All-share takeover Value: $1.3 billion

Buyer: China National Petroleum Corp. Target: Athabasca Oil Sands Corp.* Type: 40% stake** Value: $680 million * Name has since changed to Athabasca Oil Corp. **Follows $1.9 billion purchase of 60% interest in 2009

www.albertaoilMAGAZINE.com

Toyota Tsusho Corp.

Encana Corp.

Type: 32.5% share of Alberta coal bed methane acreage Value: $602 million

Global Flavor Total Horn River and Montney investment since 2008 by region

Total oil sands foreign investment since 2003 by region

Other France

5% 18%

China

29%

South Africa

2% 1% 45%

10%

Thailand

Japan

United Kingdom Korea

33%

Norway

Korea

33%

United States

Malaysia

United States

Source: Canadian Energy Research Institute, Foreign Investment in the Oil Sands and British Columbia Shale Gas

Oil Sands Ascent Production

mbpd = million barrels per day

2045 5.4 mbpd 2020 3.3 mbpd 2010 1.5 mbpd

3.2 $1.2

billion cubic feet per day of natural gas consumption in the oil sands by 2045

trillion estimated oil sands royalties collected by the Alberta government between 2011 and 2045

159 $200

megatonnes of oil sandsrelated carbon released into the atmosphere annually by 2045 billion estimated greenhouse gas reduction compliance costs paid by oil sands industry between 2011 and 2045

Source: Canadian Energy Research Institute, Reference Case Scenario, Canadian Oil Sands Supply Costs and Development Projects (2011-2045)

june 2012

the100

+ ENERGY SERVICE 50

Follow the

Leader

By Roger Tissot ILlustration Eddie Guy

Venezuelaâ&#x20AC;&#x2122;s onceproud oil industry has suffered under the rule of Hugo Chavez. But as his political future, and health, grows more uncertain, the sector could be poised for a rebound

www.albertaoilMAGAZINE.com

june 2012

the100

+ ENERGY SERVICE 50

or those of us who have followed Venezuelan political developments for years, the address by Hugo Chavez to the United Nations on September 22, 2006 was a highly anticipated event. Chavez had become a controversial figure: A mixture of political clown and visionary who liked to befriend the more unsavory world leaders as long as they were in the United States’ bad books. His performance in New York City that day did not disappoint. The highlight of his address – or lowlight, depending on your point of view – came when the leftist Venezuelan president called then U.S. President George W. Bush the devil, mocking him by saying the podium still smelled like sulfur. The anti-American tenor of his speech converted Chavez into something of an international sensation. But Chavez’s rhetorical flare for the dramatic aside, by 2006 the Venezuelan president had made a sizeable impact on the global petroleum industry. He, along with President Vladimir Putin of Russia, was the one who brought back the concept of “resource nationalism” as a central political variable redefining international relations. Chavez was the first in a group of Latin American leaders over the last decade to represent a new form of the left. Contrary to past revolutionaries, including Cuba’s Fidel Castro, Chavez identified with the people he claimed to represent because he was one of them. He was not the child of a well-to-do family going rogue, a romantic revolutionary like “el Che” Guevara, who grew up wealthy. Chavez experienced all the discrimination and hardships of the Venezuelan poor. And Chavez brought a new form of politics to Venezuela. He used popular language understood by his supporters, even if it was ridiculed by the elites who saw him as a buffoon with limited education and experience. But that was his key to

www.albertaoilMAGAZINE.com

success. Since his dramatic entry into Venezuelan politics during a failed coup attempt in 1992, he has been underestimated. The Venezuelan elite were never concerned that Chavez could bring about political change, despite rapid social, political and economic collapse in their country. Six years later, Chavez was elected president. Much like Venezuela’s elite, the world did not pay too much attention to the young colonel-turned-president, either. Oil prices averaged US$12 in 1998. Oil supermajors were investing billions developing the vast resources of the Orinoco belt in central Venezuela, a region with so much heavy oil and bitumen deposits that the U.S. Geological Survey has said the mean recoverable oil resources there totals 513 billion barrels of crude. Moreover, Chavez did not sound threatening; he initially adopted “orthodox” economic policies. In short, with low oil prices and the Organization of Petroleum Exporting Countries (OPEC) in disarray in the late 1990s, Venezuela didn’t really matter.

Alberta’s oil sands have been one of the benefactors of the fall from grace of PDSVA and the Venezuelan oil and gas industry during the Chavez presidency However, when a country has as much oil as Venezuela possesses, it always matters. Today, the country stands at a crossroads, both politically and economically. During Chavez’s 13-year reign, the country’s once-proud oil and gas industry has underperformed and grown inefficient – something that has benefitted Alberta and its oil sands sector. He is also waging what some observers suspect is a losing battle against cancer. To make matters worse, a united and organized opposition, led by a charismatic free market presidential candidate in Henrique Capriles, is presenting a serious threat to his regime. And so, with Chavez fighting – literally and politically – for his life, the question becomes: what would a Venezuela run by someone other than Hugo Chavez look like?

t’s a question the people who occupy the office towers in Calgary and Houston are asking themselves. For what happens in this fall’s Venezuela presidential election will have ramifications for the oil and gas industry both in Canada and worldwide. Chavez, despite his recent troubles, is still a formidable figure. Turn back the clock to 2006 and he had achieved an impressive political record. He had won two elections and a referendum,

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the100

+ ENERGY SERVICE 50

2.6

million barrels per day of oil is currently produced by Venezuela

survived a coup attempt and a disruptive strike from the national oil company, the mighty Petróleos de Venezuela, S.A (PDVSA). He drastically changed oil contracts and “re-nationalized” the oil industry, directly confronting ExxonMobil and the other commanding highs of the oil industry. He engaged in vast wealth redistribution programs, a massive nationalization spree, expropriating and acquiring any activity deemed “strategic” to the regime. He implemented an oil transfer program to energy dependent Central American and Caribbean countries, allowing him to gain geopolitical influence. He redirected Venezuelan foreign and petroleum policy, from a U.S.-centric strategy to one aimed at market diversification and strong integration with China, Russia and Latin America. He brought Venezuela back into the OPEC quota system, and became a leader of its price hawks. Finally, he helped to revitalize Cuba’s dying regime by exchanging around 100,000 barrels of oil every day for Cuban doctors, social workers and intelligence experts.

Currently there is no known “plan B” within the “Chavista” circles to replace Chavez With 2006 oil prices having increased five times from 1998 levels, averaging US$58 per barrel, the war in Iraq raging, and with demand from China and India suggesting that oil prices would inexorably move up, Chavez was feeling confident about the future in 2006. He expected that his rule would extend to 2021 or beyond. But the 57-year-old’s political star has faded considerably since the halcyon days of 2006. Although oil prices surpassed US$100 per barrel in 2008, he experienced his first electoral defeat in 2007 when he proposed some amendments to the constitution, including indefinite re-election for the president. Venezuela experienced a recession in 2009 and 2010 and only by 2011, fueled by recovering oil prices and massive public spending, did the economy improve. However, Venezuela today has the highest inflation in Latin America,

www.albertaoilMAGAZINE.com

138%

is how much PDVSA’s debt has increased from 2008-2011

Is the number of days it takes an oil supertanker to move from Venezuela to the U.S. Gulf Coast

its debt levels are increasing fast, and public services are deteriorating. Citizens live in constant fear due to increasing criminality and insecurity. The country’s deteriorating conditions have soured the electorate, to some degree, on Chavez. The political opposition, characterized by its incompetence and inefficiency in the past, finally launched a clever and well organized primary process in 2011. Venezuelans were exposed to a diversity of options from the candidates seeking the nomination of the “Mesa de la Unidad Democratica” (MUD) party. The chosen leader, 39-year-old Capriles, is a young and charismatic center-left politician who has cleverly focused on issues close to the day-to-day lives of Venezuelans: crime, corruption, declining services, inflation and jobs. He has avoided any direct attack on the president, calling instead for a government of reconciliation and national unity. With a total of three million votes cast during the primary elections in February, the MUD did better than expected, but it is still far below the seven million votes Chavez achieved in the 2006 elections.

enezuela’s oil production just before Chavez took office was 3.5 million barrels per day (bpd). Since then production has declined below 2.6 million bpd − although government sources claim current production at around three million barrels daily. During the “old PDVSA” the company’s objective was to produce five million barrels daily by the middle of the last decade.

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In 2005 the “new PDVSA” launched a six-year plan called “Siembra Petrolera”. It proposed oil production of 5.8 million bpd by 2012 and an investment of US$239 billion. Not only has the ambitious production goal not been met, but the financial results of the company have severely deteriorated. Its debt increased from US$2.7 billion in 2005 to near US$33 billion now. The plan also included an expansion of refining capacity, proposing the construction of four new refineries, none of which have been completed. Moreover, existing refineries suffer from constant accidents and insufficient maintenance. PDVSA’s natural gas objectives have not fared any better during Chavez’s reign. By now natural gas production should have been around 11 billion cubic feet (bcf) per day, but it has only reached 6.8 bcf. Venezuela was supposed to be a large exporter of liquefied natural gas, and its gas pipeline infrastructure should be connecting the western and the eastern regions of the country. Instead, Venezuela continues to import gas from Colombia to keep its oil production flowing from the declining Maracaibo fields. The new “Siembra Petrolera” plan for 20112015 has more modest goals than its predecessor – reaching daily production of 4.15 million bpd of oil and 13.8 bcf per day of gas by 2015. As production flatlines, PDVSA has been borrowing money at an incredible speed. From 2008 to 2011, the company’s debt increased by 138 per cent. A large component of that debt comes from China’s oil or debt scheme, perceived by many analysts as too costly for Venezuela. Moreover, not all the funds from China have been used for capital development, to the increasing consternation of the Chinese lenders.

Chavez, along with President Vladmir Putin of Russia, was the one who brought back the concept of “resource nationalism” as a central political variable redefining international relations With production stagnating and domestic demand growing, the cost of subsidising oil consumption in Venezuela is becoming a heavy burden, costing the government around US$15 billion per year. The burden is greater since PDVSA is forced to import more and more oil products because its existing refining capacity has been unable to meet domestic demand. Alberta’s oil sands have been one of the benefactors of the fall from grace of PDVSA and the Venezuelan oil and gas industry

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the100

+ ENERGY SERVICE 50

during the Chavez presidency. His anti-U.S. rhetoric, plus the threat of nationalization and expropriation, caused some of Big Oil’s players to shift their capital elsewhere, notably to bitumen deposits located in landlocked northern Alberta, which has accelerated development of the resource. But a Chavez defeat in this fall’s presidential elections, and a return to the Venezuela and PDVSA of the early 1990s, could have the oil and gas industry flocking to Venezuela once again and focusing less on investing in a high-cost resource like the oil sands. While there might not be any threat of expropriation in Alberta, the fact is crude oil from the Orinoco is far cheaper to produce and transport than oil sands crude. What’s more, it only takes five days to move a supertanker from Venezuela to the U.S. Gulf Coast.

ut whether Venezuela is poised for a regime change is open for much debate. General elections will be held on October 7, 2012. Currently Venezuelans are bombarded by an opinion poll war, but all of them show Chavez ahead. If he is healthy enough to run, he is likely to win the elections. However, his health is

000AO-ABPipeliners-1_3H.indd 1

a mystery. In 2011 he underwent an operation in Cuba to extract cancer from his pelvic region. Since then he has undergone a series of chemotherapy treatments and a second operation in February. He continues to travel to Cuba for more cancer treatment, but his public appearances are becoming more infrequent and there are rumors he is losing his fight to beat the disease. Currently there is no clear successor within the “Chavista” circles to replace Chavez, but the recent appointment of a Council of State headed by his vice-president, Elias Jaua, could be seen as a plausible transition mechanism. Inevitably some of Chavez’s close advisors are discreetly positioning for such an eventuality. Three possible successors include his brother, Adam Chavez, and Diosdado Cabello – the head of Venezuela’s National Assembly, as well as Venezuela’s Foreign Minister, Nicolas Maduro. A status quo scenario, where Chavez or a Chavista substitute is in power, would result in a slow but progressive improvement of Venezuela oil output. The ambitious expansion programs may not be achieved on time, but one can expect a positive trend. Improved governance between PDVSA and its foreign partners is likely to allow for that to occur. If so, new players would be interested in entering this country’s risky oil and gas game again. Capriles’ petroleum policies are harder to discern, but his rare comments on the matter point to favoring a strong national oil company that would be able, with different management, to achieve high levels of efficiency. What is required is simply to liberate PDVSA from all that political interference. Capriles denies any desire to privatize the company, but would like to attract more private investment in the sector. Apparently influenced by the Brazilian model, he likes to think Venezuela could learn from Norway, something Brazil claims to have done. Unfortunately, neither Brazil nor Venezuela is Norway.

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If Capriles were to be elected, the new administration will face numerous challenges starting with a National Assembly, and other key institutions, such as the armed forces, the electoral authorities and PDVSA, controlled by Chavistas. The new president would be reluctant to deviate too much from PDVSA’s current strategy. Moreover, current legislation allows the government to increase private sector participation in the oil industry. His focus, therefore, is likely to be on lifting production and improving earnings. It’s important to point out that any efforts to revive a “technocratic” PDVSA may face some political realities. Chavez’s meddling in petroleum matters caused many of Venezuela’s best and brightest petroleum minds to leave the country. The expertise lost is now leading an oil boom in Colombia; and one would doubt that after being successful in the private sector, former employees would want to return to a “government job”. As difficult as the situation is, there are reasons to believe the period of production decline in Venezuela is over. In fact, realizing its huge financial burden and numerous operational challenges, PDVSA seems willing to assign more resources to capital development. Central to the reversal of production is the US$2-billion “Tri- color” investment plan in the Orinoco belt, aimed at boosting production there to 1.6 million bpd by the end of the year. Secondly, PDVSA appears to be asking its partners to help finance its share of their joint ventures. Large companies such as Chevron and the China National Petroleum Corporation seem willing to accept the request in exchange for better governance in the joint ventures. However, the question remains if Capriles, Chavez or a Chavista successor would have the vision and capabilities to further open up the sector, improving contractual terms and offering a concession model that would bring back the capital and competition necessary to finally meet its old goal of doubling current production by the time the next presidential elections take place. If that were the case, Venezuela, free of ideological hobbles, could focus on regaining market share in its most profitable market, the U.S. Gulf of Mexico – the main target of Alberta oil producers. AO Roger Tissot is an Alberta industry veteran who has become a roving independent business consultant, specializing in his native South America.

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A DV E RTO R I A L FE ATU R E

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Albertaâ&#x20AC;&#x2122;s International Region

;jZaa^c\ LdgaY"XaVhh 8ki_d[ii 9edd[Yj_edi Albertaâ&#x20AC;&#x2122;s International Region is a hub of industrial business activity â&#x20AC;&#x201C; serving the energy, transportation, manufacturing industries and more

^[ B[ZkY#D_iak ;Yedec_Y :[l[befc[dj Authority (EDA) connects local businesses with each other as well as with the rest of the world. Seven municipalities â&#x20AC;&#x201C; Leduc County, the City of Leduc, the Towns of Beaumont, Devon, Calmar and the Villages of Thorsby and Warburg â&#x20AC;&#x201C; make up Albertaâ&#x20AC;&#x2122;s International Region, an area businesses should consider investing in for long-term growth. The EDA is your best, all-encompassing, regional development resource and support network for your business investment and expansion needs. This â&#x20AC;&#x153;community of communitiesâ&#x20AC;? is rich in resources: human energy, property in proximity to valuable assets, access to industry and major transportation connections. Albertaâ&#x20AC;&#x2122;s International Region is the gateway to opportunity.

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_jkWj[Z _d W ikX#ckd_Y_fWb Wh[W e\ Leduc County alongside the Queen Elizabeth II Highway, the Edmonton International Airport (EIA) is less than a five-minute drive from the Nisku Business Park and the City of Leducâ&#x20AC;&#x2122;s North Industrial Area. Considering 75 per cent of the areaâ&#x20AC;&#x2122;s businesses are involved with international markets, easy access to Canadaâ&#x20AC;&#x2122;s fastest-growing airport is a welcome advantage. In response to growing demand, the EIA underwent a 463,000-square-foot expansion that was completed in 2012. Expansion perks include more flight options, greener building practices (LEED certification) and a new Central Tower revealing excellent airfield views. The airportâ&#x20AC;&#x2122;s expanded Central Hall, on the departure level of the Central Tower, is a domestic and international lounge area for passengers to enjoy once they pass security. The Hall provides travellers with new retail, food and beverage options while the existing terminal now has more space, natural light and 9EDJ?DK;:

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Leduc-Nisku Economic Development Authority

I=: <6I:L6N ID DEEDGIJC>IN (International Airport cont’d) seating to enhance everyone’s experience. In 2013, the Courtyard by Marriott hotel will open on site with 123 spacious rooms and 10,000 square-feet of meeting and banquet space to accommodate a multitude of business-related events. The EIA’s nearly 7,000 acres of land will eventually have 3,000 of that filled by the AirLINKS Business Park with office space for light- to medium-industrial services. AirLINKS is endorsed by Port Alberta, the authority on transportation and logistics issues. Another EIA joint venture is with Aerotropolis Integrated Land-use Compatibility Plan, which is a 50-year projection of future EIA development, operational

needs and an approach to controlling air, traffic and ground noise. The V-configuration of the airport’s two 200-foot wide runways, both more than 10,000 feet long, have accommodated such planes as the Antonov 225, the world’s largest cargo carrier, on more than one occasion and can hold any size aircraft in the future. The EIA is Canada’s most northerly 24-hour international airport, which helps feed Alberta’s International Region with human resources and supplies required for the area’s prime and growing sectors: energy, agriculture, advanced manufacturing, environment and transportation.

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d WZZ_j_ed je j^[ ;?7Êi 7_hB?DAI Business Park, Alberta’s International Region is also home to Canada’s largest industrial energy sector: the Nisku Business Park, comprised of small- to medium-sized businesses as well as international conglomerates. The Nisku Business Park spans 5,392 acres, with about 600 companies in its boundaries. These businesses are mostly related to oilfield servicing, manufacturing, contracting and industrial services. Also within Leduc County, an additional 1,437 acres of land was approved for the Crossroads Business and Logistics Hub.

A neighbor of the Nisku Business Park is the City of Leduc’s North Industrial Area, another rapidly developing business region. This North Industrial Area is situated adjacent to the City of Leduc’s north-west commercial area and is only three kilometres away from the EIA. More than half of the North Industrial Area’s 1,565 acres are fullyserviced, developed and home to 135 operating businesses. It is expected that the region will continue to expand for the next 10 to 15 years in sectors such as oil and gas, construction, research and food production, advanced technologies and training facilities. 7H9J?9 IF7I0 Ldg`Zgh bVcj[VXijgZ \ddYh i]Vi eji i]Z ldgaY Vi ZVhZ

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Leduc-Nisku Economic Development Authority

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Alberta’s International Region (Transportation Corridor cont’d) roadway from Mexico through the U.S. CANAMEX states and into Canada – Calgary to Edmonton specifically – is being developed. The idea of CANAMEX is to enhance a trade and tourist corridor beyond this province’s borders to reach international markets. Port Alberta – an organization that promotes growth, influences leaders and solves problems for its members – supports the CANAMEX initiative. The City of Leduc, the Town of Devon and the EIA are all Port Alberta members and collaborate to enhance business connections in Alberta’s International Region. 7=H?#<EE:I0 6 i]g^k^c\ ^cYjhign i]Vi AZYjXÉh ;ddY EgdXZhh^c\ 9ZkZadebZci 8ZcigZ eaVnh V W^\ eVgi ^c

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^[ 7]h_lWbk[ FheY[ii_d] 8ki_d[ii Incubator (APBI) is a federally registered facility that supplies services to support the establishment and growth of current and upcoming business in Alberta. The Incubator program is designed to support business growth by adding value to agricultural products. It also provides the physical space and technical support required to get new products to market competitively for new and established businesses. APBI provides a modern processing facility, technical support and business management assistance for companies that is provided by on-site staff or through aZYjXc^h`jZYV#Xdb

referrals to outside consulting services. Financial assistance programs are also available to help with business planning, feasibility studies and even equipment purchases. Businesses have access to the facility’s eight fully-serviced processing bays, which have shared cold storage and centralized shipping/receiving. Additionaly, APBI assists established food manufacturers with new products and attracts process development initiatives to Alberta through new product development, commercialization, and market launching. The Food Processing Development Centre, adjacent to APBI, is a 65,000square-foot facility that provides product development and commercialization services

to new and expanding food processing companies. The facility houses a culinary lab, product development laboratories and a fully-equipped commercial pilot plant. The Centre is staffed with more than 40 employees: food scientists from multi-disciplinary backgrounds, product development specialists and processing technologists trained in the food processing industry. These specialists provide in-concept analysis, product development, pilot plant scale-up and process development, sensory analysis and consumer acceptability. Alberta’s International Region is wisely taking advantage of its available local resources, both human and environmental. 9EDJ?DK;:

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A DV E RTO R I A L FE ATU R E

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Wdc[j;D;H=O H[i[WhY^ 9[djh[" located in the Town of Devon, is dedicated to research geared towards improving processes in oil sands and heavy oil. The facility has an estimated 130 scientists, engineers and technologists, managers and support staff who work together to create new environmental technologies. CanmetENERGY’s areas of expertise include extraction and tailings, water management, multi-phase systems, upgrading oil sands and heavy oil, and future fuels and emissions. This group of experts

share their knowledge with Canadians, the industry and government policy makers to keep everyone informed with accurate, in-depth oil-processing information. The organization lends its technical knowledge to oil sands environmental assessment hearings where parliament may need proven science and potential solutions to base regulatory decisions on. With energy leading Alberta’s economy, CanmetENERGY is a necessary, forwardthinking organization with an environmentally conscious initiative.

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Alberta’s International Region EDMONTON INTERNATIONAL AIRPORT ÆI=: 9G6B6I>8 <GDLI= D; I=: AZYjX"C^h`j VgZV ^cid dcZ d[ i]Z bdhi hjXXZhh[ja dâ VcY \Vh bVcj[VXijg^c\ VcY hjeean ]jWh ^c Cdgi] 6bZg^XV ^h V iZhiVbZci id i]Z Xd]Zh^kZ VeegdVX] YZbdchigViZY Wn Wjh^cZhh VcY edaî^XVa aZVYZgh ^c i]Z gZ\^dc# I]^h Xd"dgY^cViZY VeegdVX] id gZ\^dcVa YZkZadebZci ]Vh ]ZaeZY i]Z :Ybdcidc >ciZgcVi^dcVa 6^g" edgi id WZ V `Zn ZXdcdb^X XdbedcZci d[ i]Z AZYjX"C^h`j VgZV VcY i]Z 8VeîVa GZ\^dc! VcY lZ VgZ egdjY id WZ eVgi d[ i]Z iZVb#Ç Å Cohed A[[^d" LF e\ 9ecc[hY_Wb :[l[befc[dj Wj j^[ ;Zcedjed ?dj[hdWj_edWb 7_hfehj

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bX[hjWÊi ?dj[hdWj_edWb H[]_ed _i h_]^j _d the heart of one of the world’s strongest economies with well-established and thriving resources: agriculture, energy and advanced manufacturing. The region is just minutes south of Edmonton and acts as a gateway to the second-largest global oil reserve (Fort McMurray). Organizations like Arctic Spas, Hyduke Energy Services, CanmetENERGY, the Leduc Food Processing Development Centre and the APBI are reaping the benefits of being in the perfect business location. The Leduc-Nisku EDA understands the importance of local and global connections. Formed in 1984 as a partnership between Leduc County and the City of Leduc, the EDA has effective sustainable development strategies that support businesses interested in investing in Alberta’s International Region.

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Step

Change Alberta’s slow emergence as a hub for global investment brings

with it new challenges and opportunities. Mega-projects in the oil sands are increasingly dependent on foreign capital, for instance, just as Calgary has attracted a cosmopolitan breed of corporate executive. Meanwhile, producers and energy services companies looking to broaden their horizons must navigate the sometimes choppy waters in some of the globe’s emerging economies. Proceed with caution.

Raising a Giant

A handful of firms look to crack Alberta’s carbonates

Foreign Exchange Canadian firms gain a toehold in the BRIC nations

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JUNE 2012

Step Change

Osum Oil Sands Corp. CEO Steve Spence

www.albertaoilMAGAZINE.com

Raising a

GIANT Equity investors are turning their attention to an untapped motherlode of bitumen. Has the carbonatesâ&#x20AC;&#x2122; time arrived? By Jeff Lewis // Photograph John Gaucher

June 2012

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Step Change

Carrion birds scatter as pilot Tony Laface

dips his Bell 206B model helicopter in for a close look at what’s left of a dead caribou. “As you can tell we’re pretty much in the middle of nowhere,” a voice crackles, rising above the steady clip of chopper blades. It belongs to Jen Russel-Houston, geosciences manager at Calgary upstart Osum Oil Sands Corp. She’s wedged on to the helicopter’s back bench, seated next to two public-relations handlers. The geologist and former subsurface team leader at Shell Canada Ltd. can tell clastic rocks from carbonates in a split second, but on this overcast day in late February, from 1,200 feet aboveground, roughly 70 kilometers southwest of Fort McMurray, she is having trouble distinguishing one exploration lease from another. “I don’t quite know where one begins and one ends,” she says over the headset. Suddenly a misshapen grid pops into view. On the forest floor, squiggly lines cut through stands of black spruce and poplar, forming what looks like a giant tic-tac-toe board in the northern woods. In fact, the pattern is a $10-million, 3-D seismic program. The rock underneath is a thin end of a bitumen wedge estimated to contain some 400 billion barrels of oil in place. Osum holds 175,000 net acres in the trend, better known to geologists as the Grosmont carbonates. The privately held firm believes the property could eventually yield 73,000 barrels of oil per day. Another independently owned lease to the west might eventually produce upwards of 80,000 barrels of crude per day, the company estimates. There’s just one snag. The Grosmont formation has long shone brightest among the province’s unexploited jewels, to such an extent that geologists and executives are known to whisper its name in the same breath as Ghawar, the supergiant conventional oilfield in eastern Saudi Arabia. Yet the

carbonates’ potential is regularly excluded from provincial reserve estimates, in no small part because nobody has yet figured out how to produce a barrel of the super-viscous oil (API gravity of between five and nine) at an economic rate. “Grosmont’s not new. Everybody knew it was here,” says Russel-Houston, as the chopper completes another flyover. “Everybody knew it had bitumen. It just wasn’t considered economic.”

That view might be changing.

The appeal among equity investors and deep-pocketed Asian firms for Alberta’s deposits of thick, tarry bitumen is beginning to spill over into the hard-tocrack carbonates. The trickle of interest follows a flood of foreign capital that has, in the last decade, inundated Calgary’s corporate towers. Much of the flow has originated in Asia and the United States. Companies headquartered in both regions are responsible for two-thirds of the $30.3 billion that foreign firms have spent gobbling up ownership stakes in the oil sands since 2003, according to the Canadian Energy Research Institute. >>

175,000

net acres held by Osum Oil Sands Corp. in the Grosmont formation

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OSUM

“ We’re designing our business to be self-contained, and not rely on a large partnership with a supermajor as part of our business model.”

The tide has only recently begun lapping at the elusive motherlode of raw bitumen embedded in the carbonates, which Alberta’s Energy Resources Conservation Board (ERCB) estimates could hold some 447 billion barrels of oil in place, or 26 per cent of the province’s total bitumen resources. “We’re believers that this resource will, in the fullness of time, be commercialized,” says David Krieger, managing director with Warburg Pincus LLC in New York, and an Osum director, in an interview. He is not alone. In addition to Warburg, itself a participant in three rounds of financing going back to 2008 that netted Osum a combined $815 million, the oil sands upstart counts among its backers Blackstone Capital Partners, Camcor Partners Inc., KERN Partners, Goldman Sachs and the investment arms of both the governments of Singapore and South Korea. The Korea Investment Corporation, which in 2010 exchanged $100 million for a minority equity stake in Osum, has likewise pumped $50 million into Laricina Energy Ltd., another carbonate hopeful that counts the Canada Pension Plan Investment Board among its major shareholders.

Laricina and Osum are partners on a planned 12,500-barrel-per-day commercial demonstration in the Grosmont. If it’s successful, observers say, the project would go some way toward convincing outsiders that there is more to Alberta’s oil sands – much more, the companies say – than what’s currently scraped and gouged from Fort McMurray-area strip mines. Asian investors in particular are “beginning to understand that it’s a large resource base, and obviously there’s a demand in that part of the world for that product,” says Rick Pawluk, a partner at McCarthy Tétrault LLP in Calgary and lead counsel for Sunshine Oilsands Ltd. That company has zero production of which to speak, but its toehold in the Grosmont formation was among the assets shopped around in the lead-up to a March initial public offering that raised roughly $580 million – covered in large measure by the China Investment Corp. – on the Hong Kong Stock Exchange. >>

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“ We’re believers that this resource will, in the fullness of time, be commercialized.” Sunshine’s debut on the Asian bourse is notable, not only for being the first such deal involving an oil sands player, but also because it points to a possible future for the carbonates, and the role national oil companies might play in unlocking the resource’s potential. Sunshine’s chief executive, John Zahary (also an Osum director), has signed a memorandum of understanding to explore potential joint venture opportunities with the China Petroleum & Chemical Corp. (known as Sinopec) with an eye to accelerating development of its in situ oil sands leases. “The foray of Sunshine into the Hong Kong market is fascinating,” says Osum chief executive officer Steve Spence. “We’re watching very closely how that plays out, frankly not just over the next few weeks, but really how it plays out over the next month, the next year and on from there.”

JEFF LEWIS

Spence got an early look at the carbonates

in 2006. On May 11 of that year, Shell Canada, through subsidiary BR Oil Sands Corporation, offered $2.6 billion for an all-share takeover of heavy oil middleweight BlackRock Ventures Inc. The deal gave Shell a modest production footprint in Alberta’s Peace River region. It also gave Spence a tantalizing glimpse at a narrow sliver of the Grosmont trend. At the time, he was assigned the job of integrating BlackRock’s assets – some of them in the southern

Well-site geologist Iftikhar Abid examines drill cuttings inside a mobile trailer during a winter coring program run by Osum

end of the Grosmont – into Shell’s massive production portfolio. The Canadian arm of the AngloDutch giant saw in the carbonates more or less what everyone else did, he recalls: a long-term prospect whose time had not yet arrived. The reservoir engineer in Spence saw something entirely different. Surveying the network of >>

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Step Change

fractures and “vugs” – essentially Swiss cheese-like holes that ooze bitumen – that comprise the formation, he thought, “I think we can make money with these today.” “Getting oil to move that doesn’t want to move is kind of what I’ve been doing for the last 25 years,” he says, seated in a small boardroom at Osum’s spacious and airy Bow Valley Square office. The Grosmont is unique. Spence gets visibly excited just talking about it. If it were a light oil reservoir, the executive says at one point during a lengthy interview, “This would be Saudi Arabia. Saudi Arabia never would have come on the map, frankly. We would have had the best oil reservoir in the world sitting right here.” As it is, the resource is heavy. So heavy, in fact, that early trials of thermal recovery techniques dating back to the 1970s, led variously by the Alberta Oil Sands Technology and Research Authority, Union Oil Canada and Chevron Resources Canada, have produced little in the way of commercial results. The formation is riddled with fractures, shale barriers and holes big enough to swallow drill pipe whole, notes Les Little, executive director, energy technologies, at the Energy and Environment Solutions branch of Alberta Innovates. “You need to know your geology,” he says. The agency has invested $900,000 since 2007 just researching the tough rock. In some areas, the resource “actually sticks to the sand grains, which means you need more energy to get it off, if you can get it off,” Little says. “It’s just a more difficult nut to crack.”

26%

of Alberta’s total bitumen resources are estimated to be located in the Grosmont formation

Whether or not OSUM can solve

the complex reservoir is an open question. “The company does not yet have any production and, as a result, its challenge will be to develop producing assets while minimizing [share] dilution and maintaining financial discipline,” Peters & Co. analysts Jeff Martin and Tyler Reardon wrote in March 2011. In May of that year, the analysts valued the company at between $11.76 and $19.04 per share. That translates to a market capitalization of between $1.6 billion and $2.6 billion, based on the 137 million fully diluted shares it had outstanding as of May 2012. The company’s more immediate plans involve a decidedly less stubborn oil property in Cold Lake. First oil from a 45,000-barrel-per-day, steam-assisted gravity drainage (SAGD) project called Taiga in the Lower Grand Rapids and Clearwater formations is expected by 2014. Spence says the company “will seek additional funding to sanction the project.” From where, exactly, it remains to be seen. At McCarthy Tétrault, Pawluk suggests the capital required to bring an oil sands project on stream, >>

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Step Change

especially one located in as complex a reservoir as the carbonates, far outstrips the capacity of North American markets. It’s one reason he expects more companies will follow in Sunshine’s footsteps and choose to list on an overseas exchange. “You’ve kind of got to go where the money is, right?” Which raises the question: Would Osum opt for a public listing in Hong Kong? “We’d never say never,” Spence says. The company has no plans for a public share sale, however. Nor is it relying on a deep-pocketed national oil company to prop up its balance sheet. Says Spence, “We’re designing our business to be self-contained, and not rely on a large partnership with a supermajor as part of our business model.”

If Grosmont were a light oil reservoir, this would be Saudi Arabia. That means using cash flow generated by Taiga to develop the firm’s carbonate leases, where plans call for use of a combination of steam and solvents to thin the ultra-viscous oil. “As long as you get high enough recoveries of the light hydrocarbon you’re putting in, it can be a very economic process,” Spence notes, declining to discuss specific projections. (Joint-venture partner Laricina anticipates a break-even price at its neighboring carbonate holdings below US$55 West Texas intermediate using solvent-cyclic SAGD techniques). “Early projects will have some additional, logistical challenges,” the Osum executive

$2.6

billion paid by Shell Canada in an all-share takeover of heavy oil producer BlackRock Ventures Inc. in 2006

allows, “but over time we see no reason why” costs should be different than a conventional SAGD project in the southern Athabasca region. The giant oilfield is prone to surprises, however. One morning in February, at the center of a football field-sized clearing in the woods, Russel-Houston, Osum’s geosciences manager and a veteran of pre-development work at Shell’s Carmon Creek project, is watching intently as a thin wire pulls taut. A 1970sera rig called Trinidad 64 has corkscrewed down more than 400 meters to retrieve a core sample for analysis. The geologist’s eyes are fixed on a silver tube as it emerges from the hole. There is a moment of uncertainty before she shoots drilling supervisor Ron Barron a sideways glance. “Is there nothing in there?” “It’s not catching,” Barron says, above the whine of diesel engines. The tube has come up empty. “Could be the bit we’re drilling with,” he says, bemused. He smiles. “Usually you get something.” AO

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Bengal Energy chief financial officer Bryan Goudie

www.albertaoilMAGAZINE.com

Step Change

Foreign

Exchange As opportunities in the so-called “BRIC” nations beckon, Canadian firms grapple with how to build a business in tricky territory By Beverly Cramp // Photograph Bryce Meyer

The frozen expanse of Western

Siberia spells opportunity for Canadian firms. Just ask Trican Well Service. “We just supply fracturing in North America,” says company chief executive officer Dale Dusterhoft. “But in Russia, we provide more infrastructure supplies and services such as tanks, fluid handling, tubing, tools and heating of fluids. We had to offer this bigger package because third parties weren’t available. But we charge extra for these additional supplies and it is reflected in our Russian prices.” Demand remains solid for Trican’s technical expertise and level of service in Russia, where estimated reserves top 144 billion barrels, according to the U.S. Geological Survey. The size of the Russian prize supports a late-spring deal between ExxonMobil Corp. and OAO Rosneft that gives the Irving, Texas-based giant access to tight oil prospects in Siberia and offshore reserves in the Arctic. Dusterhoft echoes an emerging view of the former Soviet Union, which along with Brazil, China and India forms the BRIC bloc of emerging market economies. “We like the area long-term,” the Trican chief says.

June 2012

Step Change

“Where we are, it is quite a mature oil field, it’s well-developed.” Trican has built its Russian operations over the past dozen years to include 1,700 staff, most of whom are Russian. Many of them don’t speak English. Senior managers conduct business through translators. On March 16 of this year, Trican furthered its commitment to the Russian oil and gas industry by establishing a research and development center in Moscow in conjunction with the Gubkin Russian State University of Oil and Gas. The goal is to develop new techniques for drilling and completion applications specific to Russia’s geology. Given the country’s reputation for tough negotiations with major oil producers, Dusterhoft’s assessment of the local business climate is surprising. “We have seen no sudden changes in the rules, nor any other regulatory disruptions,” he says.

180 countries. At the No. 1 spot for least amount of perceived corruption is New Zealand. Canada sits at number 10; Brazil and China are at 73 and 75, respectively, while India is at 93 and Russia is ranked No. 143. “It’s not surprising that countries that have strong civil institutions, respect for the law and typically democratic governments have a lesser perception of corruption,” Klotz says. “I think you can still do business in a country that is perceived to have a lot of corruption, but you’ve got to have robust anti-corruption plans in place: policies, procedures, internal controls and training. The key is training, training, training.”

“ In Brazil there are so few operators and so few bid rounds to get permits … access to land and to deals is difficult.”

Indeed, the biggest challenge for Trican

is that the Russian oil and gas servicing business has become too attractive. “It has become a very competitive environment in the last two to three years,” Dusterhoft reports. “We have had to drop the prices for our services. It’s been this way since 2009.” The company’s experience illustrates the potential risks and rewards of doing business in BRIC countries. Perhaps one of the biggest challenges western companies face is the risk of corruption. You need only look at the ongoing trials of engineering giant SNC Lavalin, or else the $9.5-million fine levied under Canada’s Corruption of Foreign Public Officials Act against Niko Resources Ltd. last year for examples of how best practices can be challenged overseas. “After the Niko case, the prosecutor warned that this is just the beginning of big fines,” notes James M. Klotz, a partner and co-chair of the international business transactions group with Miller Thomson LLP. Klotz is also president of the Canadian chapter of Transparency International, a non-governmental organization that publishes information on the perception of corruption in

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If Russia, especially Western

Siberia, is considered a “mature” oil field, then India’s is still at a fledgling stage. According to the Oil & Gas Journal, the subcontinent has approximately 5.7 billion barrels of proven oil reserves as of January 2011. Calgary-based Bengal Energy had been dipping its exploration toe into the South Asian country since 2008. Bengal was formed from a previous corporation called Avery Resources. Bengal Energy still retains Avery’s Australian assets but has also expanded into India. This was made possible due to the knowledge of its Indo-Canadian CEO, Chayan Chakrabarty. “He had contacts in India and knew about their NELP [New Exploration Licensing Policy] rounds,” says Bryan Goudie, Bengal’s chief financial officer. >>

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Step Change

$9.5

million was the fine levied under Canada’s Corruption of Foreign Public Officials Act against Niko Resources Ltd. in 2011

“Companies can bid on a work program to do initial exploratory work for four years, such as seismic studies, in various blocks of land. Then, if they find their initial exploratory results positive, they can continue developing the play for another three years. At the end of that, the procedure is to sign a contract with the Indian government to begin producing.” Effectively, royalties to the Indian government are also decided through the bidding process. “You bid on the fiscal terms, which is split between two phases: a cost recovery phase and the profit phase. During the cost phase, the terms of the permits allow companies to recoup their exploration costs. Then the profit phase kicks in, and the profits are split between the Indian government and the company, based on the terms of the bid. Many of the bids allow for companies to keep around 25 per cent of the profit. Our profit on oil is 80 per cent, which is high.” One of Bengal Energy’s land plays is surrounded by the exploration arms of much bigger oil and gas companies. “We are in an area off the east coast of India where BP recently purchased a 30-per-cent share of 23 exploration and development permits from Reliance Industries. They paid $7.2 billion for it. Our permit is in the middle of these properties.” Goudie says Bengal Energy has established good working relationships with the various Indian government agencies involved in regulating the oil and gas industry. “It’s all based on British common law,” he says. “A contract is a contract. There is a clearly-defined process. The bureaucracy may be much slower

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than what we are used to, but it is still a functioning process.” The slowness of the Indian bureaucracy is one of the biggest challenges the upstart company faces. “Everything has to be stamped, rubber-stamped, stamped again, signed and sealed,” Goudie says. “And don’t expect anything to happen on the first time through. You really need to have a dedicated document handler. If you think something is going to take a day, add another day to your calculations. We also have a country manager in India who maintains relationships with various government regulators. That’s critical because relationships are important.”

It’s a lesson Gran Tierra Energy

has taken to heart. The company entered Latin America via a small acquisition in Argentina in 2005. When it moved into neighboring Brazil four years later, in 2009, it hired Shane O’Leary, the former vice-president of Encana Corp.’s Brazilian unit, as its chief operating officer. He, in turn, attracted other former Encana staffers who had worked in Brazil’s offshore, recalls Jason Crumley, Gran Tierra’s director of investor relations. “We then had people who were very familiar with Brazil’s sub-surface, geology and also Petrobras [Brazil’s national energy company],” he says. “They had good relationships with the major players in Brazil.” Gran Tierra acquired a Brazilian oil property in August 2010 that was producing approximately 400500 barrels per day. “We drilled an additional two wells on this property,” Crumley says. “We haven’t disclosed what we are actually producing from these new wells, but our goal is to reach at least 1,000 barrels per day before the end of 2012.” Gran Tierra supplemented this Brazil asset with an offshore property when it announced in September

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Step Change

2011 that it had entered into an agreement with Statoil ASA and Petrobras to farm-in on two blocks in the Camamu-Almada basin. The Brazilian foray hasn’t been easy, Crumley says. “It’s not easy anywhere in the world, but in Brazil it is complicated by the fact there are so few operators there and so few bid rounds to get permits from the government,” he says. “The last bid round in Brazil was in 2009. So access to land and to deals is difficult.” China has been just as spotty. Estimates of oil reserves there range from 28 billion barrels (U.S. Geological Survey) to 213 billion barrels (China estimate). Calgary-based Ivanhoe Energy explores for oil and gas in China through subsidiary Sunwing Zitong Energy Ltd. In January, the company sold its 100-per-cent working interest in a natural gas exploration block in China’s Sichuan basin to Shell China Exploration and Production Company Limited, a subsidiary of the Anglo-Dutch giant. The $160-million deal is expected to close by the end of this year. Beyond freeing up Ivanhoe to develop its Tamarack oil sands project in northern Alberta, the deal highlights the difficulty of doing business in China’s budding domestic oil and gas sector. The transaction will see Shell assume a US$20-million “performance bond” Ivanhoe was initially compelled to post as part of a production sharing contract it signed with the China National Petroleum Corporation.

wells drilled by Ivanhoe Energy in the Kongnan oilfield in China’s Hebei province

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Just seven days after the company

announced terms of the deal, Ivanhoe issued an apology for the “unintentional oversight” of not first clearing the information contained in the press release with Chinese officials. Ivanhoe has since assured PetroChina that “all future communications and activities,” including press releases related to the Shell deal, will go through PetroChina first, according to a January 18, 2012, press release. Ivanhoe maintains other assets in China, despite seeing its operating costs in the country rise by $6 million in 2011 compared to 2010 due to China’s tax regulations. Under a so-called windfall levy, historically China raised taxes progressively from 20 per cent to 40 per cent on the portion of the monthly weighted average sales price exceeding $40 per barrel. That changed November, 2011, when China raised the threshold to $55 per barrel. From 2000 to 2007, Ivanhoe drilled 46 wells in the Kongnan oilfield in Dagang, Hebei province, and commercial production commenced in 2009. As the project reached cost recovery in late 2009, Ivanhoe’s working interest decreased to 49 per cent. In 2011, government quotas restricted production to 80,000 gross tonnes or 1,600 barrels per day gross. Ivanhoe’s actual production in 2011 averaged 967 barrels per day net. The production quota in 2012 remains set at 80,000 gross tonnes. Ivanhoe’s experience underscores the fact that not all emerging markets are created equal. It’s one reason Klotz at Transparency International says companies embarking on overseas forays should first acquaint themselves with local customs. Corrupt dealings have a way of surprising even the most experienced executives, he says. “It often comes up quickly, when a company is in dire straits or when an employee is faced with sudden and urgent demands for payment,” he says. “They’ll think they are doing the right thing. But if they have the proper training, they will be prepared to deal with these circumstances in the appropriate way.” One of the easiest ways to deal with sudden demands for payments is to create a paper trail. “Typically people demanding corrupt payments don’t want a light shone on these transactions,” he says. AO

Step Change

Globetrotters A new MBA program with an energy focus is drawing executives from around the world to Calgary

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By Steve Macleod // Illustration Eddie Guy

Belgacem Chariag’s accent isn’t easy to

place. For the past three years he’s been the president of eastern hemisphere operations for Baker Hughes Inc. He is currently stationed in Dubai. There are only three countries between Chariag, in the United Arab Emirates, and his native Tunisia, but he’s travelled all around the world to get there. “You name it and I’ve been there,” he says. Although born in a country that produces less than 100,000 barrels of oil per day, Chariag was inspired by the booming activity in nearby Saudi Arabia at an early age. He studied petroleum engineering at the University of Texas. Since then he’s held jobs in Europe, the Middle East, the United States and Africa. Dan Lumma, executive vice-president of energy markets and strategy with Houston-based engineering and construction firm Kiewit, nods in agreement as Charaig speaks. The two energy industry veterans are becoming acquainted over a glass of wine at the Calgary Golf and Country Club. While working in the energy industry has allowed both of them to travel the world, this isn’t the first stop in Calgary for either one of them. Lumma’s been with Kiewit for 22 years. He grew up in the U.S. Midwest, graduating from the University of Missouri with an electrical engineering degree. He’s been travelling to Calgary semi-regularly since 2004. “When I first came up here it was a niche market in the oil and gas business,” he recalls. That has changed. “It has become apparent Calgary is not just a niche market, it’s a critical oil and gas hub.”

The city’s rise mirrors Alberta’s ascent as

a destination for global capital. That, in turn, has fueled a desire for a new class of corporate executive, one who can move seamlessly between a remote well site at Bowden, Alberta, and the gleaming towers of Beijing. Cue the Global Energy Executive MBA program at the University of Calgary, known by its awkward-sounding acronym, GEMBA. The university’s Haskayne School of Business partnered with white-shoe consultancy IHS CERA to create the program. It gives energy executives from around the world access to an MBA program focused solely on the industry they work in. It’s also recognition that the southern Alberta city is quickly shedding its Cowtown image. “Calgary’s role is increasing in the world,” says Harrie Vredenburg, the program’s academic director. Vredenburg says he has been pushing for an MBA program specifically tailored to energy industry executives for several years. He helped design the University of Calgary’s master-of-

science program in sustainable energy development, but he only got his wish after Len Waverman became the dean of the Haskayne School of Business, in 2008. “He sat down with a group of us and said, ‘we need to think big,’” Vredenburg recalls. A partnership was struck with IHS CERA and Vredenburg started working with academics from around the world to develop a new program. GEMBA students will spend about two weeks on-site in four key energy markets around the world during the 16month program. In between the learning modules, students will participate in online sessions and work with their peers through virtual discussions. Completing an MBA program has always been a personal goal for Chariag, but it didn’t always gel with his professional role at Baker Hughes. GEMBA changed that. “The convenience to come in for two to three weeks, then do it from home and work virtually was important,” the 49 year-old says.

“ I hope to be able to think more strategically and analyze things to think with a broader interest.” Part of the reason GEMBA was structured in such a fashion was the recognition that many of the students needed to stay on their career paths. “For most of these people, the next stop is the c-suite and this is the last polish they need,” Vredenburg says. “We’re going to attract the highest flyers from around the world and in a short period of time, they’ll be running companies all around the world.” >>

June 2012

Step Change

The inaugural class of 20 students is one-

third foreign students and the rest are from Canada. At a welcome reception held for the class this spring, David Hobbs, chief energy strategist with IHS CERA, marveled at the experience on hand. He wasn’t the only one to notice. That some of the students are a little long in the tooth is one of the reasons Kunle Babalola was drawn to the program in the first place. The principal partner with El-Parazim Consulting Services in Calgary completed a master’s degree in petroleum engineering at the University of Dalhousie in Halifax and then did one semester of an MBA. His fellow students were kids, he recalls. “They were all young children and I wanted a program that would fit into my lifestyle and my ambitions,” the 40 year old says. The larger appeal of the program, though, is its unvarnished focus on the energy industry. Vredenburg says there are other MBA programs – in Houston and Norway, in particular – that offer options focused on energy. “This is unique in that we focus only on energy,” he says. All of the case studies and examples provided by professors will come from the energy industry, so students don’t have to learn strategies implemented by Southwest Airlines or Toys “R” Us and figure out how to apply them to the oil business.

“ We’re going to attract the highest flyers from around the world and in a short period of time, they’ll be running companies all around the world.”

was presented to him, it changed Vicq’s thinking. “All of the cases, assignments and discussions will be about the industry we live in every day,” he says. “I hope to be able to think more strategically and analyze things to think with a broader interest.” The executive training course is accredited by the Association of MBAs, but for the first intake of students, at least, its credibility also comes from the Haskayne School of Business, IHS CERA and the realization Calgary is not just a hub for leading oil and gas producers in the world. Increasingly, it’s viewed as a city that can produce leaders for the world. “When you’re in the western part of the world you know Calgary,” says Chariag of Baker Hughes. “But even in other parts of the world it’s known for innovation, entrepreneurship and technology.” AO

Around the World in 16 Months The Global Energy Executive MBA has five modules that will last for a couple of weeks in key energy centers around the world. In between the residencies, the students will complete assignments from home, participate in online tutorials and discussions with other students.

April 2012 Business Leadership Essentials Calgary and Banff – 2.5 weeks

August 2012 Balancing Shareholder Value, Risks and Stakeholder Interests London, England – 2 weeks

January 2013 That focus was enough to convert John Vicq, manager of business and commercial shale gas for Nexen Inc., into a student, despite the fact he had no previous ambitions to earn an MBA. Vicq graduated from the University of Saskatchewan with a bachelor of commerce degree and since it was pre-Bakken and pre-boom times in Saskatchewan, he headed to Alberta and joined Arthur Andersen LLP. Most of Vicq’s clients at the accounting firm were in the oil and gas industry, so it was just a matter of time before the chartered accountant moved in-house. The 41-year-old has been with Nexen for 11 years and when the idea of an energy-focused MBA

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Navigating Industrial and Economic Transformation Abu Dhabi, UAE and Beijing, China – 2.5 weeks

March 2013 Managing Innovation, Climate Change and Sustainability Houston – 2 weeks

July 2013 Taking Charge of the Future Calgary and Banff – 2.5 weeks

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dividends

Finding Zero

Natural gas stocks may already reflect a price recovery

By Eric Nuttall THE MOST OVERLY ANTICIPATED TRADE OF 2012 HAS

been the natural gas trade. Given the thrashing these stocks have received over the past few years, it was (is) a commonly held belief that there was (is still) a lot of upside in the stocks once the price of natural gas begins to recover. Yet there are now reasons to question this belief. Universally it is understood that the current natural gas price is totally unsustainable over the long term, and that a rally of at least 100 per cent is required in the long run to incentivize drilling. Despite liquids-rich gas drilling, service cost deflation, pad drilling, and other cost-decreasing initiatives, most would agree that a price of US$3.50-$4.00 per 1,000 cubic feet is required in the long-run for most natural gas companies to generate adequate rates of return. With a current price below the long-run marginal cost of production it’s commonly believed that as natural gas prices recover, so too shall the stocks. Many investors believe that we’ve reached the bottom in natural gas stock prices. I disagree. I’m still waiting for the point of maximum pessimism – marked by extreme widespread pessimism towards an investment by the investing public. This is often the best entry point because the last seller has thrown in the towel and stocks are discounting the worst-case scenario. Are we there today? Not by a long stretch, despite a recent rally that has seen Encana Corp. become the top-performing large-cap energy stock in Canada, outperforming some of its more oil-weighted peers by more than 30 per cent so far this year. Despite the poor equity performance over the past several years, natural gas stocks never came close to discounting at a price lower than $3. Perversely, with the rally in NYMEX prices from a low of US$1.90 to a recent high of US$2.40, many natural gas stocks have risen by more than 20 per cent. Yet, when one looks at valuations, it appears that stocks are now discounting a significant portion of a natural gas price recovery close to what I believe will be a ceiling price for the next several years until liquefied natural gas capabilities materialize in 2017. At current natural gas prices, a select basket of natural gasweighted stocks are trading at 17 times enterprise value to cash flow. Multiples will always be highest when close to a cyclical

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bottom in pricing, but if one looks at valuations using a US$3 or US$4 natural gas price, the average multiple decreases to only 11 to eight times. On a cash flow metric basis, one could argue that natural gas stocks are already pricing in a significant recovery in the price of natural gas. Even on a price- to net-asset value basis, many natural gasweighted stocks are trading at a 150 per cent premium or higher to their 2P net asset value based on an average gas price of US$3.75 over the next six years – hardly a bargain. The opposite situation exists in the oil-weighted universe. Fears over European and Chinese economic stagnation have made oil stocks in the past few months quite weak. Compounding this is the performance lag experienced in 2011, where the price of oil rallied while oil stocks performed poorly. As a result, valuations to me in the oil space are extremely compelling.

Many investors believe that we’ve reached the bottom in natural gas stock prices. I disagree. For example, an oil company and Sprott Energy Fund holding that I find especially compelling is trading at one times proved net asset value (using US$90 long-term oil). Future development capital equals 2.4 years of cash flow, so reserves do not appear to be overbooked. An investor today can buy this company at slightly under the blow down value of its proved reserves and thus by definition get their probable reserves (31 million barrels of light oil), possible reserves, and risked unbooked resource barrels (83 million barrels of light oil) for free. So which sounds more compelling to you? Buying a $1.6-billion enterprise value light oil company with $44 netbacks at $90 oil that is growing production by over 20 per cent and is trading at proved reserve value, or buying a natural gas stock that has netbacks of $10 today, flat production growth, a stressed balance sheet at current gas prices, and is discounting a natural gas price recovery of over 100 per cent? To me, the answer is obvious. AO Eric Nuttall is a portfolio manager with Sprott Asset Management LP based in Toronto and a frequent contributor to the Business News Network.

contr ast

Double Take

Petrobank Energy and Resources Ltd. and PetroBakken Energy Ltd. closed 2011

the same way they closed 2010: by reporting identical financials. The two companies have been intertwined since October 2009 when Petrobank merged its light oil and natural gas assets with TriStar Oil and Gas Ltd. In exchange, Petrobank took a 59 per cent ownership stake in the newlyformed PetroBakken. Revenue from PetroBakken’s production has helped fund Petrobank’s development of new technology for heavy oil production in the company’s two other business units. While John Wright is leading both Petrobank and PetroBakken as president and CEO, there are some differences between the two publicly-listed companies, beyond a corporate-name suffix.

Petrobank

PetroBakken Shares

Petrobank’s share price on the Toronto Stock Exchange closed the week of October 6, 2009, at $47.77. The company’s share price opened May 2012 at $14.17. Petrobank recently initiated a normal issuer course bid to sell 6.03 million of its shares in PetroBakken, as well as reinvest the dividends it receives from the subsidiary to repurchase Petrobank shares. John Wright’s right hand man at Petrobank is Chris Bloomer. The senior vice-president and COO of the heavy oil business unit started his career in the oil sands with Shell Canada Ltd. in 1978. Wright and Bloomer also sit on the company’s nine-member board of directors. Wright serves as a director on PetroBakken’s board, too.

Petrobank’s heavy oil business was dealt a blow at the start of the year when proved reserves for its Kerrobert project in Saskatchewan were adjusted to zero. The Saskatchewan test site for the company’s patented toe-to-heel air injection (THAI) technology earned proved reserves of three million barrels of bitumen in 2010.

The firm continues to plug away at the Kerrobert site. Production there during March averaged 264 barrels per day (bpd). The company has $10 million in capital expenditures planned for the site in 2012 and is focusing on bringing production up to commercial rates of 1,000 to 1,200 bpd. It plans to continue developing in situ technology through subsidiary Archon Technologies Ltd.

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PetroBakken also debuted on the Toronto Stock Exchange on October 6, 2009. The closing share price at the end of the company’s first week was $35.20 and a dividend of $0.08 per share was distributed for October. PetroBakken’s share price opened May 2012 at $14.40. A year earlier (May 2, 2011) the stock hit a 52-week high of $18.29.

Personnel

Operations

Outlook

PetroBakken has nine people on its executive team, which until April 5, 2012, included Gregg Smith. He was senior-vice president and COO of Petrobank’s Canadian business unit before taking his title over to the newly formed PetroBakken in 2009. No replacement had been named for Smith as this magazine went to press.

PetroBakken recently sold some assets in Saskatchewan that the company deemed “non-core.” The sale earned PetroBakken $427 million and the company still has land in the province’s Bakken formation. PetroBakken has light oil properties in Alberta’s Cardium formation and natural gas assets in northeast British Columbia’s Horn River and Montney plays.

As well as selling off non-core assets in Saskatchewan, PetroBakken made three other recent transactions bringing in a total of $622.5 million. The sale of those assets dropped production in March, but the company still finished the first quarter averaging 20,700 barrels of oil equivalent per day in the Bakken and 16,400 barrels of oil equivalent per day in the Cardium. AO

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Alberta is energy. But where does it go from here? This month, Jim Carter answers that question

People Power

Addressing a skilled labor shortage can position Alberta as a world energy leader By Jim Carter Alberta continues to experience

a growing economy. And it’s growing – even in the face of global uncertainty – because of an abundance of marketable natural resources, an educated and talented workforce and an optimistic “can do” approach and attitude. But as the province expands its gross domestic product, and strives to become a global energy player, it faces a significant challenge: maintaining and growing a skilled workforce. Several forecasts illustrate how serious the situation is. By 2019, according to Alberta Human Services projections, the province is expected to be short 77,000 skilled workers. The Alberta Coalition for Action on Labour Shortages predicts an even greater skills deficit, as it expects the shortage to grow to 114,000 over the next decade. This is being felt on the ground as well. Labor supply pressures experienced in 2007 and 2008 are resurfacing. But this challenge presents the province with an opportunity – and a potential solution – and that’s engaging young Albertans in career discovery. I have first-hand knowledge on how this can be done. Back in the early 1990s, when I was responsible for Syncrude Canada’s operations, I was a founding member of the Co-op Apprenticeship Program in Fort McMurray. This initiative attracted posthigh school Albertans into the trades. The success of this program led to a pilot project with the Alberta Chamber of Resources to expand the concept into the high schools

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with career exploration programs such as the Registered Apprenticeship Program. The pilot project worked, and led to the creation 15 years ago by my colleague, Eric Newell, of CAREERS: The Next Generation Foundation. This is a “made in Alberta” solution and an industry-led public-private partnership aiding in building a skilled workforce. It provides a variety of career options to students across Alberta by providing internships with employers. This link of “learning to earning” provides the opportunity for students to test drive a career while obtaining school credits and training hours.

A critical element in building the future skilled workforce is engagement of young aboriginal people. For many students, exploring a career path while in high school adds relevance to learning. I’ve witnessed many students in the program that have become much more engaged in learning and better community members. These students are in most cases very motivated, productive, innovative and become leaders in the workplace. This is a win for the student, the school, the employer and the community. Today, CAREERS is working in 511 schools in 288 communities and has resulted in 1,500 internships with approximately 1,000 employers. A total of 16,198 student interns have been placed with employers since 1997.

Jim Carter is the former president of Syncrude Canada and chair of the Alberta Carbon Capture and Storage Development Council

Of course, there is more to solving Alberta’s labor shortage than creating training programs. Another piece of the puzzle is making use of underutilized segments of the population. I believe a critical element in building the future skilled workforce is engagement of young aboriginal people and their communities. The aboriginal population accounts for 5.8 per cent of Alberta’s population and is growing at triple the rate of the non-aboriginal population. But it remains an untapped talent pool. Many in the oil and gas industry continue to be challenged in attracting and retaining aboriginal people in the workplace. This is a huge opportunity, particularly with many of our industries located close to aboriginal communities. Collectively, the energy industry must build on successes in engaging the aboriginal population in the economy. It typically involves more effort and commitment from the organization, and it requires working with one student at a time to ensure mutual success. But the work can pay big dividends. In my experience, the aboriginal population is a large untapped pool of human resource talent that should be utilized before turning to other alternatives – such as pursuing temporary foreign worker programs to satisfy Alberta’s employment needs. If Alberta is to reach its fullest economic potential, it needs to employ creative measures such as these to attract young people of all cultural backgrounds into the opportunities that exist here at home. If we can do that, it will go a long way towards Alberta becoming a global energy player. AO This is the sixth in a series of guest columns. Remember to check albertaoilmagazine.com/ shapingalberta for future and past submissions

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