Oil & Gas Inquirer June 2013

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CONTENTS

JUNE.13

in the news

Alberta looks north for oil pipeline routes

regional news

British Columbia

DeeThree reports 1,580-barrelper-day Belly River oil test

Northwestern Alberta

Alberta shelving shallow rights reversion plans

Northeastern Alberta

• Ease of Use for Field Operators

Southern Alberta

Keyera, Plains propose new Deep Basin liquids pipeline

Cenovus enters blowdown phase at Foster Creek

• Portable Gas Test Measurement Utilizing Vortex Meters and Systech Smart Deadweight

Central Alberta

April land sale generates $40.5 million

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Meeting the world While international money flows into Canada’s oil and gas sector, Canadian companies invest around the globe

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Arab nations invite Alberta firms to Middle East

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Political Cartoon

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OIL & GAS INQUIRER • JUNE 2013 RERIUQNI SAG & LIO • 3102 ENUJ

Is your oilfield services operation ready for serious competition? Focus on finance fundamentals to grow profits in tough markets. When you’re wrapped up in managing day-to-day business operations, it can be hard to step back and see the big picture. Over the last fifteen years, the Canadian oil and gas industry has enjoyed enormous growth. In 1998 the value of all the oil and gas produced was $27 billion. By 2008 it had risen to $145 billion. Last year it was $110 billion. From 1998 to 2012, annual capital spending on oilsands development alone increased fifteen fold – from $1.5 billion to $23 billion. This spending has helped the Oilfield Services (OFS) sector expand significantly. But can these companies remain competitive when the growth stops?

These volatile market conditions require OFS companies to explore internal efficiencies in order to remain competitive, or in some cases, afloat.

The end of overall growth is complicated by ever-changing customer requirements. The collapse of gas prices has shifted drilling and development dramatically, leaving equipment and services that were profitable for years sidelined. The switch to oil and horizontal drilling has created demand for other products and services and solutions to new technical challenges. Market dynamics have caused demand for some equipment and services to explode while others have collapsed.

“Finding cost efficiencies in your own operations is essential,” says Yager. “MNP’s Oilfield Services specialists know where to find opportunities to improve financial performance, through key activities like job costing and margins, field ticket flow, collections, cash management, and inventory control. Good financial management is always a sound investment. In this market it is imperative”.

As a result, OFS companies have had to constantly adjust their products, equipment and services just to stay in the game. “When the industry was in a period of steady expansion, it was easy for OFS companies to grow profits,” says David Yager, National Leader of MNP’s Oilfield Services practice. “High demand drove growth, but now, with capacity up and demand flat or falling, securing a profitable piece of a shrinking and ever-changing pie has become more challenging.”

“Going forward, profit growth will come more from internal operations, not the overall marketplace,” explains Yager. “When the industry landscape has changed this dramatically, companies must course correct or risk financial challenges.” MNP’s Oilfield Services team has the financial management tools to help make the most on whatever business comes in the door.

To find out more about how MNP’s Oilfield Services team can benefit you, contact David Yager, Oilfield Services National Leader, at 403.648.4188 or david.yager@mnp.ca.

David Yager, Oilfield Services National Leader

Editor’s Note Vol. 25 No. 5 EDITORIAL EDITOR

Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS

Lynda Harrison, Carter Haydu, Richard Macedo, James Mahony, Pat Roche, Elsie Ross, Paul Wells EDITORIAL ASSISTANCE MANAGER

Marisa Sawchuk | msawchuk@junewarren-nickles.com EDITORIAL ASSISTANCE

A world of opportunity

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Michael Gaffney | mgaffney@junewarren-nickles.com CREATIVE SERVICES MANAGER

Tamara Polloway-Webb | tpwebb@junewarren-nickles.com CREATIVE LEAD

Cathlene Ozubko GRAPHIC DESIGNER

Peter Markiw

CREATIVE SERVICES

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Monte Sumner | msumner@junewarren-nickles.com SENIOR ACCOUNT EXECUTIVES

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Denise MacKay | atc@junewarren-nickles.com DIRECTORS CEO

Bill Whitelaw | bwhitelaw@junewarren-nickles.com PRESIDENT

Rob Pentney | rpentney@junewarren-nickles.com DIRECTOR OF SALES & MARKETING

Maurya Sokolon | msokolon@junewarren-nickles.com DIRECTOR OF EVENTS & CONFERENCES

Ian MacGillivray | imacgillivray@junewarren-nickles.com DIRECTOR OF THE DAILY OIL BULLETIN

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With the Canadian oil and gas industry in the midst of an exploration and production renaissance thanks to the application of extended reach horizontal drilling and multistage fracturing technologies to tight formations, it’s easy to miss that there is a whole world of opportunity beyond the country’s borders. But if you take a look around, there has been an explosion of exploration and development in recent years across the globe, and in many cases Canadian companies are leading the charge. In 2011, Canada’s top 30 international companies produced over 1.3 million barrels equivalent per day from operations on every continent except Antarctica. Through a series of discoveries in the AsiaPacific, Talisman Energy Inc. has positioned itself as the preferred partner of many government oil companies in the region. Nearly a quarter of Talisman’s production and revenues are generated from operations in Indonesia, Vietnam and soon Papua New Guinea. Dozens of Canadian operators are active in South America, producing over 400,000 barrels per day from fields in Colombia, Peru, Ecuador and Argentina. Toronto-based Pacific Rubiales Energy Corp. alone netted almost 128,000 barrels equivalent per day of production from South America in the first quarter of 2013, generating $1.3 billion in revenues. Canadian explorers can also be found in the Middle East and North Africa, with a number like Talisman reporting major discoveries in northern Iraq.

Subscription Inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2013 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

With North American service and supply markets saturated, Canadian technology companies are also reaching out globally to expand business. Precision Drilling Corporation, which less than a decade ago retrenched in the Canadian market, is now a major player in the United States and growing into Mexico and the Middle East. Ensign Energy Services Inc. is active in every major petroleum basin. Fracturing and completion specialists like Trican Well Service Ltd. and Calfrac Well Services Inc., long active in Russia, are now pioneering their technologies in South America, the Middle East and Australia. What makes all this interesting is that at a time when foreign investment in Canada’s petroleum industry is booming, with international producers and government-owned enterprises spending tens of billions of dollars gaining a foothold in shale plays and oilsands operations, the Canadian industry is increasingly focused on carving out its own piece of the global oil-and-gas pie. All this is turning Calgary from a regional centre into one of a handful of global centres with the financial clout to back world-class projects and the technical ability to identify and profitably produce resources in any environment. As governments open up to foreign investment in their extraction industries, a world of opportunity is opening up to Canadian explorers and technical service companies. The next few years should be exciting. Darrell Stonehouse

Editor dstonehouse@junewarren-nickles.com

N E XT I S S U E July/August 2013 A look at tight oil plays in central Alberta and the growing natural gas liquids plays in western regions of the province.

Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as ”Letter to the Editor” if you want them published.

OIL & GAS INQUIRER • JUNE 2013

FAST NUMBERS

394

35 per cent

Number of publicly traded Canadian oil and gas companies.

Canada’s share of the world’s publicly traded oil and gas companies.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

M O NTH

OIL

GAS

OTHER

MONTH

OIL

GAS

D RY

SERVICE

T O TA L

Apr 2012

403

141

127

671

Apr 2012

608

192

157

988

Jun 2012

205

254

Jun 2012

376

449

Jul 2012

348

488

Jul 2012

660

105

873

Aug 2012

380

541

Aug 2012

682

148

986

Sep 2012

447

524

Sep 2012

813

908

Oct 2012

1,121

105

1,269

Oct 2012

588

691

Nov 2012

535

137

750

Nov 2012

930

214

1,250

802

164

1,054

Dec 2012

483

105

639

Dec 2012

Jan 2013

313

381

Jan 2013

542

645

Feb 2013

449

124

640

Feb 2013

899

161

1,161

Mar 2013

544

149

119

812

Mar 2013

949

198

127

1,295

Apr 2013

481

129

701

Apr 2013

581

146

127

868

Wells Drilled in British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

OTHER

TOTAL

Apr 2012

244

Apr 2012

172

221

Jun 2012

334

Jun 2012

144

154

Jul 2012

401

Jul 2012

232

248

Aug 2012

454

Sep 2012

Aug 2012

296

309

465

Oct 2012

493

Sep 2012

302

310

Oct 2012

453

480 372

Nov 2012

571

Dec 2012

636

Jan 2013

Feb 2013

Mar 2013

139

Apr 2013

208

*From year-to-date

T O TA L

JUNE 2013 • OIL & GAS INQUIRER

Nov 2012

346

Dec 2012

282

317

Jan 2013

174

179

Feb 2013

358

389

Mar 2013

323

342

Apr 2013

STATS

AT A

GLANCE

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, May 9, 2013 Source: Rig Locator

Alberta, May 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

AC T I V E (Per cent of total)

Western Canada

OIL WELLS

Alberta

GAS WELLS

Apr 13

Apr 12

Apr 13

Apr 12

Alberta

508

601

15%

Northwestern Alberta

177

159

110

British Columbia

49%

Northeastern Alberta

Manitoba

Central Alberta

182

160

Saskatchewan

122

127

Southern Alberta

126

677

803

16%

481

407

137

WC TOTALS

TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, May 9, 2013 Source: Rig Locator

Alberta, May 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada

Alberta

AC T I V E

C OA L B E D M E T H A N E

Alberta

BITUMEN WELLS

Apr 13

Apr 12

Apr 13

Apr 12

275

469

744

37%

Northwestern Alberta

British Columbia

Northeastern Alberta

Manitoba

20%

Central Alberta

138

204

32%

Southern Alberta

344

637

981

35%

TOTAL

169

130

Saskatchewan

WC TOTALS

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OIL & GAS INQUIRER • JUNE 2013

IN THE

NEWS Issues affecting Canada’s E&P industry

Alberta looks north for oil pipeline routes

Photo: Joey Podlubny

The Alberta government is scouting out possible new ways to get crude oil and refined products to market in the wake of mounting public opposition to crude oil pipelines, said the province’s energy minister. Most recently, the government has hired Canatec Associates International Ltd., a Calgary consultant experienced in northern development, to do some research on the potential for an oil pipeline from the central Mackenzie Valley to the tidewater at Tuktoyaktuk, N.W.T., on the Beaufort Sea, Ken Hughes said. From there, it could be loaded onto tankers for shipment to Asia. There is already an Enbridge Inc. pipeline that transports oil from Norman Wells to Zama, Alta., he pointed out. In 2014, the Northwest Territories will have full control over its resources

and the government knows there are companies that are currently active in exploration, he said. Husky Energy Inc., ConocoPhillips Canada and MGM Energy Corp. in a joint venture with Shell Canada Limited were all active in the central Mackenzie Valley area this past winter. The Northwest Territories government is in the same situation Alberta is, which is looking at ways to get its products to market, according to Hughes. However, while t he Tuktoyakt uk harbour is relatively deep, the Beaufort is a shallow sea and the approaches are in shallow water, according to Doug Matthews, an energy consultant who worked with governments in the north for 25 years. In order to be able to ship out large volumes of crude, considerable dredging or the construction of a

Alberta is looking to ship oilsands crude through the Northwest Territories.

20-kilometre pipeline to deeper waters of fshore where la rge ta n kers could anchor for loading would be required. “It could be done, but the cost would be very high. But if there is no alternative....” he said. “If one were a prospective N.W.T. producer, it would be a good news story because then you could get your oil onto this Alberta-funded pipe and that would be great,” said Matthews. “But having said that, I think the technical challenges are pretty big and the political challenges are big; we don’t build pipelines with ease in the Northwest Territories.” The Alberta government has also just begun preliminary research on another proposal: a railway that could transport products from the oilsands to the existing marine oil terminal at Valdez, Alaska, said Hughes. The Alaska route is not the only northern proposal under consideration. Hughes said the government is still looking at the Port of Churchill on Hudson Bay as a potential outlet for diesel fuel produced in Alberta and moved to Churchill by rail—once the province has a surplus. Communities in northern Canada would be the likely market for the diesel fuel from the North West Redwater Partnership. The 50/50 joint venture between North West Upgrading Inc. and Canadian Natural Resources Limited is building a refinery in Alberta’s Industrial Heartland that will convert 50,000 barrels per day of bitumen into diesel fuel. The long-term plan is to expand to 150,000 barrels per day, in three 50,000-barrel-per-day stages. “All of these are sort of ‘let’s do some research, let’s get the response back as early as we can and see if it’s worthy of more research,’” he said. — DAILY OIL BULLETIN OIL & GAS INQUIRER • JUNE 2013

In The News

Horizontal wells, metres drilled on the upswing While the 12,000 wells predicted by the Petroleum Services Association of Canada (PSAC) in its spring update are modest compared to boom times seven or eight years ago, the percentage of horizontal wells keeps climbing, as do the total metres drilled. In its second update to the 2013 Canadian drilling activity forecast, the PSAC forecasted a slight increase in Canadian drilling for the year. During a luncheon address, Mark Salkeld, president and chief executive officer of the services industry group, noted that of the 12,000 wells expected this year, 68 per cent or 8,168 are expected to be horizontal. That’s compared to 65 per cent last year. In 2009, 29 per cent were horizontal. Mirroring this, total metres has continued to climb; that figure is expected to hit 25.2 million in 2013 compared to just over 22 million in 2012. Salkeld noted that over the last four years or so, the number of wells drilled has remained fairly even, but the proliferation

of horizontal drilling is changing the way activity levels are measured. “No longer do we have the days of 20,000 wells,” he noted, “but we continue to contend that the well count is no longer the single best indicator of activity levels and the performance of our industry at present.” The average number of metres per well is expected to rise to 2,100 in 2013 from 2,000 the previous year. Je f f Fet te rly, pr i nc ipa l a nd oi lfield services analyst with Peters & Co. Limited, said that crude oil fundamentals remain mixed; differentials and takeaway capacity are the most important issues for Canadian producers. The natural gas outlook has improved, but weather and demand—for example, fuel switching—will be key variables for the coming quarters. “On t he Canadian side, producer budgets suggest that activ it y at this point should be down modestly on a year-to-year basis,” he told the luncheon.

Pricing pressure is expected across most service lines through at least the first half of this year. Fetterly said that gas storage in the United States will probably peak at about 3.7 trillion to 3.8 trillion cubic feet in 2013, down year over year. The big driver for that is weather and demand. But supply, he said, has been “stubborn.” “Our view is that supply is not going to contract,” he predicted. That’s due to well productivity and associated gas. Associated gas coming out of the Eagle Ford, the Permian, some of the Oklahoma plays and the Bakken last year climbed by 1.7 billion cubic feet per day and should grow by a similar amount this year. “From an order magnitude standpoint, it’s now just over seven billion cubic feet a day coming out of those plays where natural gas is not the principal commodity driver,” Fetterly said. In the Marcellus, supply grew by two billion cubic feet per day last year and should climb at a similar clip this year, “and approach 10 billion

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In The News

cubic feet a day out of that region when you include the Utica as well.” Fetterly sees activity for triple rigs in the Western Canadian Sedimentary Basin (WCSB) showing early signs of momentum. The acceleration of plays such as the Duvernay, the Horn River and the Liard are expected to generate meaningful growth opportunities for deeper rigs, but there is a limited ability for the current WCSB drilling fleet to meet this demand. “Clearly, demand in the very deep side of the market is going up; the capacity has not been there to meet that,” he said. He used the Duvernay as a high-level example. In 2010 there was one well rig released, the following year had 12 drilled, and in 2012 there were 48 drilled. He estimated 100 would be drilled there this year, and 200 in 2014. “Our estimate is that the rig demand in 2014 will be over 30,” he said. “You put the Duvernay with the Wilrich, Montney, Horn River, Liard, and I think there could be over 100 rigs required to be built in Canada over the next five years to meet that resource play demand.” — DAILY OIL BULLETIN

Deloitte predicts flat oil prices, improving gas prices in long term An oversupply of oil in the United States, continued oil drilling, and a lack of infrastructure and export permits are likely to result in relatively flat oil prices over the long term, says a new price forecast. “With no significant export solutions on the horizon, we don’t expect to see much long-term change in oil futures pricing,” Andrew Botterill, senior manager of Deloitte LLP’s Resource Evaluation and Advisory practice, said as the firm released its quarterly Canadian domestic oil and gas forecast. The practice was created in 2011 after Deloitte acquired AJM Petroleum Consultants. While in the last 12 months long-term West Texas Intermediate (WTI) futures prices were in the US$90–$95-per-barrel range, they have softened and are now closer to $85 per barrel, Botterill said. “So while we are seeing quite robust pricing, there is the thought of, ‘where are all these volumes coming from, and where are they going to go in the long term?’”

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There’s also the question of whether demand on the oil side will grow along with those prices, he said. However, after previously lowering its real forecast for long-term oil prices to $85 per barrel, the Deloitte team has increased its 2013 and 2014 price forecasts by $2 per barrel in response to near-term upward price movements. The WTI longerterm outlook, though, remains relatively unchanged at $88 per barrel in real dollars for 2015 and 2016, settling back to $85 per barrel from 2017 through 2021. In the first quarter of this year, the differential between WTI and Edmonton Par Oil has been around $7 per barrel due to the Canadian volumes of oil being backed out from the U.S. market because of pipeline constraints, and Deloitte is forecasting a differential of $5 per barrel for 2013 and 2014. That is expected to return to the historical WTI-to-Edmonton-Par differential of $2 per barrel in 2015, with further rail

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In The News

transport and major pipeline reconfigurations and optimizations. As for natural gas, despite the fact that prices are still depressed, Botterill is cautiously optimistic about long-term prices. “Although there is less data in the longterm portion of the price forecast, it is still a very good barometer for long-term optimism,” he said. Withdrawals through this past winter have reduced storage volumes to closer to the five-year average, resulting in a slightly higher near-term natural gas price, Botterill noted. “With major U.S. markets expected to move toward natural gas for power generation, long-haul trucking and fuel for rail transport, we believe we may see a gradual rise in the natural gas price,” he

said. “The establishment of LNG [liquefied natural gas] export terminals, now being discussed, would also help to give the currently depressed natural gas price a longerterm boost.” Deloitte is forecasting an Alberta AECO real price of C$3.35 per thousand cubic feet in 2013, up 15 cents from the company’s last forecast in December. Gas prices are forecast to rise to $3.70 per thousand cubic feet for 2014 and $5.20 per thousand cubic feet in real dollars by 2021. Deloitte’s forecast commentary also includes an adjustment in the pricing ratios for natural gas liquids (NGLs). Historically, the price forecast looked at five-year weighted averages, but given the rapid drop in propane prices and a more gradual increase in pentanes plus prices,

Deloitte felt a little bit more comfortable going forward using more of the average over the past 12 months, he said. As a result, Deloitte has decreased its propane price forecast for 2013 and 2014 to 40 per cent of Edmonton Par Oil from 55 per cent, while forecasting a pentanes plus price 115 per cent that of Edmonton Par Oil to reflect the increasing oilsands demand for pentanes plus as a diluent. Pentanes plus, in fact, is the only NGL Canada imports significant volumes of, and the country is expected to continue imports because of the strong oilsands demand. The forecast price of butane remains unchanged at 85 per cent of Edmonton Par Oil, based on the weighted average of the last five years. — DAILY OIL BULLETIN

Chemical industry expansions could add billions to Alberta economy By Pat Roche

Further processing of oil and natural gas in Alberta could pump billions of dollars per year into the province’s economy. That’s the fi nding of a study commissioned by Alberta’s Industrial Heartland A ssoc iat ion, wh ic h wa s c reated i n 1998 by the municipalities with land inside Alberta’s Industrial Heartland, a 582-square-kilometre block northeast of Edmonton that bills itself as Canada’s largest hydrocarbon processing region. The non-profit group commissioned Schlenker Consulting Ltd. to estimate the potential economic impact of expanding the local processing of Alberta resources such as natural gas liquids, raw natural gas and bitumen. It looks at potential expansions

Average income per worker during the operation of two hypothetical plants converting raw hydrocarbons into higher-value liquids was estimated at $94,000, well above the overall average Albertan income of $58,000 last year.

to Alberta’s petrochemical and fertilizer industries. Oil and gas extraction generates roughly a quarter of Alberta’s gross domestic product, but the overall manufacturing sector generates only seven per cent, the study said.

Of that seven per cent, roughly 12 per cent comes from petrochemical and fertilizer production. However, the same chemical producers generate about a quarter of the net corporate provincial income taxes paid by the manufacturing sector as a whole.

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JUNE 2013 • OIL & GAS INQUIRER

In The News

“Concern is often expressed regarding the relatively small share of manufacturing activity in the province, given the natural resource production that occurs in Alberta, especially since there are so many ways of adding value to hydrocarbon products,” the report said, but warned that such ventures must be commercially viable. While weak gas and bitumen prices have obvious downsides, the upside is the improved profitability of industries that use those commodities as feedstocks, the report said. “This has created an opportunity to expand these industries in the province, as well as to stabilize provincial government revenues.” The study estimated that chemical industry expansions using hydrocarbon feedstocks over the next decade could generate $2.4 billion per year in additional Alberta gross domestic product. The report said this is slightly more than the entire output of Alberta’s current chemical industry. It estimated provincial government revenues would rise by about $240 million per year and about 8,500 permanent jobs would be created, along with $800 million per year in wages. (These numbers exclude the benefits of construction and possible further Alberta processing of products such as polyethylene or polypropylene.) Average income per worker during the operation of the various projects was estimated at $94,000, well above the overall average Albertan income of $58,000 last year. The study developed economic-impact estimates for two hypothetical plants converting raw hydrocarbons into higher-value liquids. The fi rst is a refi nery that would convert 150,000 barrels per day of bitumen into refined products such as diesel fuel and vacuum gas oil. The second is a 96,000-barrel-per-day gas-to-liquids (GTL) plant that would convert methane into refined products such as diesel and naphtha. Development of such a plant in Alberta is still being considered by South Africa’s Sasol Limited, though the company has decided to proceed first with construction of a similar plant in Louisiana where it can take advantage of its existing chemical complex, Louisiana state incentives and lower construction costs. Alberta’s big attraction is an abundance of cheap gas. Each of these projects would add $2 billion per year to the Alberta economy and $200 million per year to provincial government revenues, the study estimated. It said the refinery and GTL projects would

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In The News

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create 6,300 jobs and 3,800 jobs per year, respectively, and about $1 billion per year in labour income between them. While bitumen upgrading in Alberta is out of favour with some large producers, other value-adding ventures are moving more quickly. This includes an expansion at Williams Energy (Canada) Inc.’s Redwater facility upgrade propane for export to the United States and a planned expansion by NOVA Chemicals Corporation of its polyethylene production capacity, set to start construction this year. The report says NOVA expects to add a third polyethylene reactor, with the capacity to produce between 950 million pounds and 1.1 billion pounds of polyethylene per year. It would use existing ethane cracking capacity in Joff re, Alta., to produce ethylene, which would serve as feedstock for polyethylene production. Start-up is slated for 2015. Meanwhile, one bitumen upgrading and refining project is currently under construction. North West Redwater Partnership is building a refinery in Alberta’s Industrial Heartland that will convert 50,000 barrels per day of bitumen into diesel fuel. The longterm plan is to expand to 150,000 barrels per day.

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The study estimated that chemical industry expansions using hydrocarbon feedstocks over the next decade could generate $2.4 billion per year in additional Alberta gross domestic product.

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B.C.

BRITISH COLUMBIA WELL ACTIVITY APR/12

APR/13

Wells licensed

APR/12

APR/13

Wells spudded

APR/12

APR/13

Rigs released

▲

British Columbia

▲

Source: Daily Oil Bulletin

April land sale generates $40.5 million

The Montney continues to generate interest at B.C. land sales.

Powered by two parcels that combined for total bids of $32.47 million, the B.C. government collected $40.5 million at its April land sale. The provincial government sold 15,760 hectares at an average of $2,570.10. Yearto-date, industry land spending has risen in the natural gas–prone province to $97.17 million on 45,489 hectares at an average of $2,136.03 per hectare. To the same point of 2012, the government had collected $81.1 million for 63,025 hectares at an average of $1,286.75. The bonus bid high at this week’s sale came from O & G Resource Group Ltd., which paid $16.96 million for a 5,016-hectare lease that produced an average price of $3,381.55. The parcel included three tracts at I-94-G-08, J-94G-08 and G-94-G-08.

Plunkett Resources Ltd. paid a bonus of $15.51 million for the other parcel, a 5,853-hectare lease, which produced an average price of $2,650. It also included three tracts at J-94-G-08, K-94-G-08, L-94G-08, E-94-G-08 and F-94-G-08. Brad Hayes, president of Pet rel Robertson Consulting, said all the expensive parcels in the sale appear to be driven by the Montney. Most of the land is posted for deeper rights only—below the base of the Charlie Lake or Halfway—which makes the Montney the primary target, he said. “The most expensive parcels appear to be pushing the main Montney fairway northwestward through an area where shallower zones are already developed with horizontal and vertical wells along structural trends,” Hayes noted. — DAILY OIL BULLETIN

Photo: Joey Podlubny

AltaGas focused on LNG exports AltaGas Ltd., which is partnering with Idemitsu Kosan Co., Ltd. of Japan, is in the best position to deliver natural gas for export from Canada ahead of other proposed projects, the company’s shareholders heard in late April. “Currently we have the only natural gas pipeline [Pacific Northern Gas Ltd.] that ties western producers right through to Canada’s northwest coast,” David Cornhill, chairman and chief executive officer, told the company’s annual meeting. Proposed liquefied natural gas (LNG) exports could begin as early as 2017, subject to consultations with First Nations and the completion of a feasibility study, permitting, regulatory approvals and facility construction, AltaGas said in its first quarter of 2013 report.

AltaGas and Idemitsu each own a 50 per cent interest in the AltaGas Idemitsu Joint Venture Limited Partnership that will pursue opportunities involving exports of LNG and liquefied petroleum gas (LPG) from Canada to Asia. “The partnership opens up new markets for Canada, which we believe is critical for the Western Canadian Sedimentary Basin,” said Cornhill. AltaGas sees investment opportunities of between $2 billion and $5 billion, including a 600 million cubic feet per day expansion of Pacific Northern Gas (PNG), to support LNG investment initiatives, said Cornhill. “We see no limits to the opportunities here and do believe this business will

drive a significant amount of growth in the medium- and long-term,” he said. The joint-venture partners are currently conducting feasibility studies for both initiatives with the LNG study expected to be completed in early 2014 and the LPG study this year. Idemitsu is targeting 25,000 barrels per day of LPG exports, said Cornhill. PNG ha s a lso completed a pre feasibility study, which addressed pipeline capacity additions to the system. And in the second quarter of 2013, it expects to proceed to the next stage of development, including engagement with First Nations a nd u nder ta k i ng a n env i ron menta l review process. “Our strategy is to capitalize on opportunities that the renaissance of natural OIL & GAS INQUIRER • JUNE 2013

British Columbia

gas and clean energy are creating,” said Cornhill whose company’s business segments include gas, power and utilities. AltaGas’s footprint has expanded across North America and has built significant competitive advantages in strategic locations,

he said. “These locations and their demand for clean energy provides us with ample opportunity for future growth.” AltaGas also has made substantial progress in its northwest British Columbia runof-river hydro projects, which include the

Forrest Kerr, McLymont Creek and Volcano Creek generation facilities, which remain ahead of schedule and on budget. The 195-megawatt Forrest Kerr project is nearly 80 per cent complete and is on target for expected commissioning in mid-2014.

Four new LNG projects proposed Four new, major international liquefied natural gas (LNG) project proposals have come forward following an expression of interest by the B.C. government on Crown land at Grassy Point near Prince Rupert, the province announced in April. The new project proponents include Nexen Inc. Joining Nexen in its submission is CNOOC Limited; INPEX Corporation, a petroleum company based out of Japan; and JGC Corporation, a global engineering company. Woodside Petroleum Ltd., Australia’s largest independent oil and gas company also expressed interest. Woodside now

operates six of the seven LNG processing trains in Australia. SK E&S Co., Ltd., a multi-utility player in northeast Asia’s gas and electricity business, based in Korea and Imperial Oil Resources Limited and ExxonMobil Canada round out the proposed projects. T he process was star ted in late February, following conversations with First Nations. The expression of interest was officially closed on March 18. Grassy Point is in the same area where a project was cancelled nearly three decades ago. In the 1980s, a project that would have

supplied 2.35 million tons of LNG annually to Japan for a 20-year period was eventually cancelled in 1986. Construction of a $500-million pipeline, a $2-billion gas liquefaction plant near Prince Rupert and a $1-billion fleet of Japanese-built LNG tankers were all part of the project. Mobil Oil Corporation, on behalf of its Canadian subsidiary Mobil Oil Canada Ltd., said at the time that both buyers and sellers of the LNG decided to end talks without reaching an agreement. Mobil and Petro-Canada had been major players in the project since May 1985.

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British Columbia

The project was initially started by Dome Petroleum Limited about five years before the cancellation but, due to its own fi nancial difficulties, Dome was forced to withdraw in June 1984. As for the recently concluded process, proponents were asked to identify their fi nancial capacity to build an export facility, experience with LNG operations and plans to source the natural gas required to support LNG development. Proponents were also asked to include a project description, plans for First Nations and community engagement and consultation, and the potential to work in collaboration with other companies. Proposals that met the criteria are now undergoing further evaluation by the provincial government to determine exactly how many projects the Grassy Point site can accommodate. Once arrangements are in place, successful proponents will be in a position to move forward with fi nal planning and investment decisions, the province said. — DAILY OIL BULLETIN

Imperial/Exxon Mobil still evaluating potential LNG sites Imperial Oil Limited and its parent Exxon Mobil Corporation are continuing to look at potential sites for a liquefied natural gas (LNG) export terminal in British Columbia. Imperial and Exxon Mobil submitted a joint expression of interest on Crown land at Grassy Point, near Prince Rupert, but it is only one site the partners are looking at. “We’re looking at several sites and this is part of the process you go through,” said Rich Kruger, Imperial’s chairman, president and chief executive officer. “There aren’t any big financial commitments with it. But it’s an expression of interest to look at with the Crown what we can do on that potential site—as we look at others,” Kruger told reporters after the company’s annual meeting. Factors Imperial/Exxon Mobil consider for an LNG site include deepwater access to the sea, land stability and construction costs. “We’ll look along the coast at this site

as well as others to see what best meets our needs,” he said. Kruger said it’s too early to say how Canada’s West Coast stacks up against other potential global locations for an LNG export project. That depends on such factors as the size and quality of the gas resource and the cost of developing that gas and delivering it to a liquefaction plant. “It’s a bit dependent on the size and the economies of scale you can get in a plant,” Kruger said. He said other factors are LNG markets, fiscal terms and regulatory conditions. Asked whether Imperial now has enough gas to support a B.C. LNG project, Kruger noted the company’s large land position in the Horn River shale play and its acquisition of successful B.C. gas producer Celtic Exploration Ltd. “We’re early into the Celtic evaluation. We’re excited about the resource potential

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in both the former Celtic lands and the Horn River,” he said. “As an upstreamer by background, I always like more resource.... We’ll keep working on that. But I think right now the efforts are really defining what it is we have.” Asked whether a decision to proceed would hinge on securing oil-linked prices from LNG buyers, Kruger said it would depend on many factors—including the gas supply, construction costs, the land, the fiscal terms and LNG export markets. “Imperial/Exxon Mobil will do all the things we can do on the technical and engineering aspects of it to verify resource, to lower costs,” he said. “But at the end of the day you have to have the market dimension, and then the right fi scal and regulatory terms and provisions to make a project attractive.” — DAILY OIL BULLETIN

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The move to build a $25-billion oil refi nery on B.C.’s west coast took a major step forward as David Black, president of privately held Kitimat Clean Ltd., signed a memorandum of understanding with the Industrial and Commercial Bank of China Limited in April. The Victoria Times Colonist, a Glacier Media Inc. newspaper, reported the deal will see the bank act as both financial adviser to the project and provide fi nancing for the refinery, pipelines and other elements of the project, which Black said could be in service by 2020. “They see their role fi rst as providing a fair amount of money themselves, but also organizing the club of banks that will provide all the debt money,” Black said from Beijing. “It’s the biggest bank in the world, so they have the money, but they like to spread risk around like insurance companies.” Industrial and Commerce Bank officials said in a statement that they are “very pleased to be working toward a comprehensive agreement to fi nance a refi nery in

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Canada, which is planned to export refined fuels to China and other Asian countries in the future.” The amount of the bank’s cash investment is not disclosed, but Black said “they will take a big chunk of it.” When speaking with reporters following the Insight Canadian Oil Sands Summit in Calgary on February 5, Black said there were a lot of potential stakeholders he has been speaking with regarding the project, and once he knows they are behind the refi nery it should be a fairly simple task to raise the necessary funds. During that summit, the Black Press Ltd. owner said he would know by early April whether the proposed world-class 550,000-barrel-per-day oil refi nery—that could process Alberta oilsands at Kitimat, B.C.—would proceed. However, the death of the fi nancial intermediary president in March set back his schedule somewhat. On March 6, Black told the B.C. Chamber of Commerce that the refinery’s projected cost would be $16 billion, and the project would likely be accompanied by an oil pipeline costing an additional $6 billion that would not get built otherwise, as well as a gas pipeline costing $2 billion and, possibly, new ocean-going tankers for an additional $1 billion, bringing the total to $25 billion. According to Black, the entire project would be debt-financed, rather than investors taking a stake in the assets. He said the deal announced maintains that plan. “I’ve always said they [China] are the obvious buyers for the oil and fuel, and they have agreed they will not ask for control of any parts of the businesses,” he said. “That includes the refi nery, a marine terminal, a pipeline, possibly, and a tanker fleet. They aren’t asking for control of anything.” Black said the bank deal is the most important step in making the refinery a reality, and the fi nancing agreement adds to the credibility of the project in Canada.

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NORTHWESTERN ALBERTA WELL ACTIVITY APR/12

APR/13

Wells licensed

113

APR/12

APR/13

Wells spudded

APR/12

APR/13

102

Rigs released

▼

Source: Daily Oil Bulletin

N.W. Northwestern Alberta

Keyera, Plains propose new Deep Basin liquids pipeline

Photo: Joey Podlubny

Keyera Corp. and Plains Midstream Canada ULC, an indirect subsidiary of Plains All American Pipeline, L.P., say they have entered into an arrangement to solicit interest in the construction of a jointly owned natural gas liquids (NGLs) pipeline system in northwestern Alberta. The proposed pipeline system, to be called the Western Reach Pipeline System,

The new pipeline will run from the Gordondale area to Fort Saskatchewan, Alta.

is anticipated to run from the Gordondale area to Alberta’s NGL energy hub in Fort Saskatchewan. Keyera and Plains have begun an open season process seeking non-binding nominations for volumes to underpin construction. During the first stage of the open season, interested parties are required to complete and execute a confidentiality agreement and non-binding indicative nomination form. The deadline for submitting the documents is May 15. Keyera and Plains anticipate that the pipeline will consist of two new-build pipelines, with one dedicated to a mixture of propane, butane and condensate (NGL mix) and the other intended for segregated condensate service. The Western Reach Pipeline, expected to be approximately 570 kilometres in length, will travel through the Deep Basin area of Alberta, which contains some of the most prospective liquids-rich geological horizons, including the Montney and Duvernay zones, that are being developed in western Canada. The companies said they believe that separate dedicated pipelines for NGL mix and segregated condensate will benefit customers, avoiding the costs associated with pipelines operating in batch mode. Customers on the Western Reach Pipeline will have the option to direct their NGL mix and segregated condensate to a variety of fractionation, storage, pipeline and terminal facilities at the Fort Saskatchewan energy hub. Both Keyera and Plains have significant NGL fractionation, storage, pipeline and terminal facilities in the Edmonton/ Fort Saskatchewan area. These facilities enable customers to access high-value

markets for their propane, butane and condensate production. Keyera operates the Fort Saskatchewan Condensate System, consisting of extensive, interconnected condensate pipeline, terminalling and storage facilities that provide customers with access, storage and end-market delivery options. Plains operates an extensive network of pipelines with connectivity to ship NGLs to its eastern infrastructure assets, which include the Sarnia fractionation and storage facility, the Windsor and St. Clair storage facilities and the Eastern Delivery Systems.

570

kilometres

Length of the Western Reach Pipeline System

Both Keyera and Plains are evaluating expansions of their respective NGL fractionation facilities in Fort Saskatchewan to provide additional fractionation capacity for the growing volumes of NGLs produced in western Canada. Keyera and Plains will each have a 50 per cent ownership interest in the Western Reach Pipeline, which Plains will construct and operate. Based on current plans, it is anticipated that the pipeline could be operational by late 2015, assuming timely completion of the open season and regulatory processes. The capital cost will be determined once volumes have been confirmed and the engineering design has been completed. OIL & GAS INQUIRER • JUNE 2013

Northwestern Alberta

Steen River drilling boosts Strategic volumes Sharply higher crude oil production boosted total volumes for Strategic Oil & Gas Ltd., which more than doubled revenue in 2012, also boosting it substantially in the fourth quarter. While posting no positive earnings in either reporting period, the company considerably narrowed its losses from those recorded in the comparable 2011 periods. Oil and natural gas liquid (NGL) volumes jumped 123 per cent in the quarter, rising 184 per cent in the full year, thanks to successful drilling at the company’s Steen River property in northwestern Alberta. In the fourth quarter, oil and NGL volumes jumped to 2,107 barrels per day from 943 barrels per day in the fourth quarter of 2011, while full-year volumes rose to 1,871 barrels per day from 659 barrels per day in 2011. Strategic drilled 18 net wells at Steen River in 2012, reporting a 100 per cent success rate. Of these, 17 targeted Keg River and Sulphur Point oil, with 16 vertical wells and one horizontal drilled during the year. In addition, the company drilled one Muskeg Stack horizontal well in the first quarter of 2012. Drilling was focused on the rim of the Steen River astrobleme, which has shown high oil deliverability from several formations, management said.

In December 2012, Strategic closed an acquisition of light oil assets at Steen, including production capability of 340 barrels equivalent per day (83 per cent oil, 200 barrels per day tied in), pipelines, facilities and roads that the company said are strategic to its operations in area. Strategic’s capital spending last year included facility upgrades and expansion of storage capacity at the Steen River oil facility. Another 3,000 barrels of oil storage capacity and a second tanker truck loading station were added to accommodate higher volumes. Through that acquisition, road, pipeline and facility synergies reduced 2013 capital spending on infrastructure by over $12 million, the company said. The company said it added 3.7 million barrels equivalent of proved and probable reserves in 2012, excluding production, for a reserve replacement ratio of 479 per cent. Strategic also boosted proved plus probable oil and gas reserves by 55 per cent and the net present value of its reserves before tax (discounted at 10 per cent) by 54 per cent compared to the previous year, according to independent reserve evaluators McDaniel and Associates Consultants Ltd. Management attributed declines in Strategic’s natural gas volumes from 2011 levels to the shut-in of its Larne property

in July, due to forest fi res, natural production declines and lower spending on gasweighted assets. The Larne field was put back on production in late December 2012, the company said. In order to diversify its revenue stream, access to market and minimize production downtime due to pipeline disruptions, the company struck an agreement to transport up to 1,500 barrels per day of oil production by rail starting in December 2012. In the three months ended Dec. 31, 2012, Strategic’s net loss narrowed to $5.92 million from $16.19 million in the fourth quarter of 2011. Funds flow from operations in the quarter rose to $3.58 million from $824,000 in the 2011 period. Capital spending (excluding acquisitions) in the quarter advanced to $15.47 million from $12.65 million in the 2011 period, while revenue jumped to $15.86 million from $8.61 million. In the 12 months ended Dec. 31, 2012, the junior’s net loss narrowed to $4.79 million from $24.65 million in 2011. Funds flow from operations advanced to $20.02 million from $745,000 in 2011. Capital spending (also excluding acquisitions) climbed to $62.61 million from $46.03 million the prior year, while revenue jumped to $56.51 million from $22.85 million. — DAILY OIL BULLETIN

Land sales halted in woodland caribou ranges For the first time, the Alberta government has deferred the sale of new mineral rights across the entire range of two of the 15 woodland caribou herds on provincial lands until the cabinet has adopted range plans describing how critical habitat will be protected to recover the two populations. In a letter to the Alberta Wilderness A ssociat ion (AWA), A lber ta Energ y Minister Ken Hughes said that as of May 1, new mineral rights sales will be halted across the Little Smoky and A La Peche herd ranges northeast of Jasper National Park until range plans are approved, which are expected in 2014. “We really want to celebrate as this is an important shift,” Carolyn Campbell, 30

JUNE 2013 • OIL & GAS INQUIRER

conservation specialist at the AWA, said in an interview. When companies acquire mineral rights, they expect to develop them, which just makes it more and more difficult to protect the needed habitat, she said. “It is important to stop adding to those new lease pressures; now we still have hard work on the ground in terms of figuring out how to decrease the disturbance that’s there now, and our view is we haven’t even scratched the surface of what we could be doing with the technology that would allow us to shrink that footprint today and still develop leases.” The government also has withdrawn from its May 8 Crown land sale three parcels totalling 1,280 hectares, of which

about 1,000 hectares is actually within the Little Smoky caribou range, along with two parcels totalling 3,840 hectares in the A La Peche range. Both areas have been the focus of Montney exploration in the last few years. The two areas were selected because they were the most affected, said Alberta Energy spokesman Bob McManus. The parties who posted the lands have been notified and until the caribou range plans are approved, there will be no rights offerings in those two ranges said Stephanie Molina, a department spokeswoman. At this time, the government is not considering putting holds on lands outside these two ranges, she said.

Northwestern Alberta

While this is the first time mineral rights have been halted for caribou habitat protection, the government also put a temporary hold on the issuance of new Crown mineral rights when it was working on the draft of the Lower Athabasca land use plan, she said. “The temporary hold will allow our government to begin the essential work of developing comprehensive range plans in these two important caribou areas as part of the federal recovery strategy for woodland caribou in Alberta,” said Hughes in his letter to the AWA. The federal government’s boreal woodland caribou strategy, fi nalized in October 2012, mandates that provinces develop range plans for woodland caribou survival. Caribou range plans will describe how critical habitat will be protected to attain a minimum of 65 per cent undisturbed habitats over time, and provide a range-specific path forward for the recovery of that caribou population. “We do want to applaud the Redford government for taking this step, which other governments have refused,” said Campbell. “For decades, environmental groups have been saying of Little Smoky that this is too much development, too fast, and all at once,” she said. In 2005, a mult i-sec tor g roup of t he A lber ta Caribou Committee recommended that all new mineral leases be halted in caribou herds that are at imminent risk of local extinction. However, between 2009 and 2010, the government sold off 84 per cent of the land in two townships of relatively undisturbed land in the Little Smoky range. That is now being developed with numerous new wells, new roads parallel to existing ones and new pipeline corridors, said Campbell. “That is just not responsible in our view when we could be doing it differently,” she said. “With all the gains that have been made in horizontal drilling, we really feel that if there is a will by industry and also a fi rm hand by government, we could really be reducing today’s footprint by judicious use of horizontal drilling.” While acknowledging that might add to the cost of energy production, without those changes “we are going to be losing Alberta caribou and it’s going to be t he ac t of t h is generat ion,” sa id Campbell.

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N.E.

NORTHEASTERN ALBERTA WELL ACTIVITY APR/12

APR/13

Wells licensed

APR/12

APR/13

Wells spudded

135

APR/12

APR/13

139

Rigs released

▲

Northeastern Alberta

▲

Source: Daily Oil Bulletin

Cenovus enters blowdown phase at Foster Creek By Lynda Harrison

Photo: Joey Podlubny

Cenovus Energy Inc. has started moving wells on three pads at Foster Creek into the final phase of production, called blowdown, which is a first at a major commercial steam assisted gravity drainage (SAGD) project, intended to decrease the steam to oil ratio and eventually increase production. “As we reduce steam injection and co-inject methane, we expect that well productivity in those pads will naturally decline. The steam is then reallocated to new pads and, over time, drives new production,” Brian Ferguson, president and chief executive officer, said during the company’s first-quarter results conference call. As SAGD wells are prepared for blowdown, steam injection is reduced and pressure is maintained with the co-injection of methane. In full blowdown, the well continues to produce without steam, which lowers operating costs. The steam is then redirected to a newer well pad. One well pad at Foster Creek entered full blowdown mode in the fi rst quarter, and two more are being converted. Meanwhile, the company is deferring a planned second-quarter turnaround at the project, a turnaround at Christina Lake is expected to cut production by about 5,000

barrels per day, net, and spending is being cut at Pelican Lake. A turnaround at Foster Creek is being deferred to optimize the work required. Its timing is yet to be determined, and the impact of the turnaround is still included in the 2013 production guidance. Pelican Lake’s production response from its infill and polymer f lood program is slower than expected, so the company is reducing spending there by about $80 million. The reduction relates to deferral of facility construction and a reduction in the rig count to two from four rigs later this year, said Ferguson. Pelican Lake’s production is now expected to exit the year between 27,000 and 29,000 barrels per day. Cenovus’ overall production climbed to 271,058 barrels equivalent per day during the first quarter of 2013, compared to 262,850 barrels per day in the same quarter of 2012. The company’s average daily oil production in the first quarter of 2013 was 15 per cent higher than in the same period in 2012, primarily led by growth at Christina Lake where output averaged 44,351 barrels per day net, an increase of 79 per cent from

Cenovus will add around 85,000 barrels per day of production by 2014.

a year earlier, resulting mainly from the successful ramp-up of the Phase D expansion. The substantial increase in production at Christina Lake resulted from Phase C reaching full capacity in the second quarter of 2012 and the start-up of Phase D in the third quarter of 2012, which reached a one-day high of 100,176 barrels per day in the quarter. However, first-quarter production at Christina Lake felt the effect of treating issues, unplanned plant outages related to commissioning construction, electricity supply and pump failures. These factors resulted in a loss of production of approximately 1,000 barrels per day for the quarter. Combined output from Foster Creek and Christina Lake averaged 100,347 barrels per day net in the fi rst quarter, up 22 per cent from the same period in 2012. Foster Creek output averaged about 56,000 barrels per day net, down two per cent from the same period a year earlier due to higher-than-expected downtime on some production wells. A higher than usual number of wells came off production as a result of downhole mechanical issues, resulting in a loss of production of approximately 4,000 barrels per day for the quarter. Efforts are under way to resolve the downhole issues and Cenovus expects volumes to return to near full capacity of 120,000 gross barrels per day in the third quarter of 2013. There are now five phases operating at Foster Creek and four at Christina Lake. Expansions continue at each of these projects, with a combined 85,000 barrels per day of gross production capacity expected to be added before the end of 2014. Foster Creek operating costs increased $1.18 per barrel due to increased fuel prices, volume and workforce, partially off set by a reduction in repairs and maintenance activity. C h r i st i n a L a ke op e r at i ng co st s decreased $2.40 per barrel due to the increase in production. OIL & GAS INQUIRER • JUNE 2013

Northeastern Alberta

Productivity key to oilsands construction

Moving employees off -site can save big money in oilsands construction costs.

Productivity was the focus of two presentations on oilsands construction in Calgary during April. Efficiency during construction may mean adding employees, but it might also mean just the opposite, a construction contractor told an industry audience, although he meant neither layoffs nor job attrition. David Claggett, president of Kiewit Energy Canada Corporation, said oilsands employers can save money by analyzing their on-site project workforce before and during construction, moving off-site those employees who don’t need to be in the field. “It just makes sense to try and move those employees off-site, to try and drive everybody’s costs down and make the projects more competitive,” he said during a presentation to a Speaker Series event hosted by JuneWarren-Nickle’s Energy Group’s Oilsands Review. Still, identifying the task is one thing, carrying it out is quite another. At Imperial Oil Limited’s Kearl oilsands project site in northern Alberta, Kiewit’s team initially thought they could safely move about one-quarter of the project’s workforce off-site. “But when we got to thinking about it more, we thought maybe we could move 40 per cent,” Claggett said. “We tried for that, but at the end of the day, we got to 33 per cent.” 34

JUNE 2013 • OIL & GAS INQUIRER

That translated to 250 man-years, meaning about 125 people were moved offsite over two years. For Claggett, analyzing employee habits and on-site movement was key to the work at Kearl. Just one metric—how often an onsite employee put on work boots—turned out to be one of the most reliable indicators of who needed to be on the project site. Early on, it became clear that employees who donned work boots only to get from the company bus to the project office—and the reverse going home—did not need to be in the field, and could work as well off-site, in Calgary, for example. In addition, the lower costs of keeping employees in Calgary would mean savings for the employer. Claggett acknowledged some employees have to be on site. This group includes tradesmen and field workers, as well as field and front line supervisors: “the folks that execute the work.” Beyond these groups, however, he believes many job categories are “fair game” for being moved away from the project site, with potential savings for employers. At the end of the day, one thing that can block progress in relocating employees is resistance to change. Simply put, some of those who faced relocation felt strongly that any such move was a step backward.

“The biggest impediment to making this work, to some degree, is the biases people have,” he said, repeating a typical response from those asked to move. “I’ve got to have my scheduler right next to me, or right in my office,” he said. Other employees will argue they’ve “got to have these guys sitting one door down from me.” Yet, “if you accept that these people don’t need to be there, you can [usually] figure out how to communicate with them remotely,” Claggett said, citing video conferencing as among the most useful tools for off-site engineers, for example, for keeping in touch daily with employees as project construction proceeds. By his estimate, employees on some oilsands projects spend five to six hours per day video conferencing during a project’s construction phase. For Tim Weber, project manager for Devon Canada Corporation on Stages 2 and 3 of the Jackfish oilsands project, a balance has to be struck between the goals of improving productivity, on one hand, and safety, on the other. At Jackfi sh 2 and 3, Weber’s team succeeded in cutting engineering costs by about 30 per cent, mainly achieved through reducing construction, procurement and fabrication costs. At the same time, he said roughly three to six months was shaved from scheduling, thanks in part to lessons learned on Jackfish 1. A key lesson, Weber said, was the value of a major soil stabilization initiative on Jackfish 3. Earlier, Devon realized from bitter experience that poor soil conditions at the project site could slow progress on several fronts. For Jackfish 3, the company invested $5 million to $6 million in soil stabilization, a project that took about 55 days to complete. The money was well spent, Weber said, estimating it saved one to t wo months on the project schedule, yielding substantial productivity improvements during construction. At the same time, the ease with which equipment and vehicles could move around the work site after soil stabilization helped improve employee morale. On that score, Devon took other steps to boost morale. Aware that workers at the

Photo: Joey Podlubny

By James Mahony

Northeastern Alberta

Jackfish site could jump ship if they found other projects that offered better terms or living conditions, the company took a number of steps to improve camp life. That included building a district lodge, with amenities such as games rooms, a theatre and other perks for employees living at the project site. When asked, employees had earlier identified privacy as an issue. Of all the aspects of camp life, the lack of privacy in living quarters bothered many. In response, Devon built living quarters with single, private rooms, each with its own bathroom, for employees. That’s a far cry from the past, when oilpatch workers in some parts of Alberta bunked four or six workers to a trailer, with showers often some distance away in another trailer. As for cost escalation on Jackfish 3, “we’re pretty much where we want to be in terms of the budget,” Weber said.

New technologies cutting greenhouse gas emissions By Elsie Ross

Within the international community, the real focus is on greenhouse gas (GHG) emissions in relation to the oilsands, and new mining and in situ projects are addressing those concerns, said an industry spokesman. “We can talk about the improvements that we have made over the past 20 years,” Greg Stringham, vice-president of markets and oilsands for the Canadian Association of Petroleum Producers (CAPP), said in a presentation to a recent industry event. “We have dropped our greenhouse gas emission footprint in the oilsands per barrel of oil produced by 26 per cent over that 20 years—just over one per cent per year— and people are looking for that to be a real key focus and commitment on behalf of the industry.” In recent meetings in Washington, he responded to criticism that the oilsands has

a larger carbon footprint than other forms of energy with information about the most recent technologies that are now in place. “These are the best in class, agreed,” said Stringham, acknowledging that earlier projects may have a larger footprint. The GHG footprint of Kearl, Imperial Oil Limited’s new mining project that will be coming on shortly, will be just two per cent higher than the United States average GHG footprint for all of its oils, both light and heavy, he said. “So we are getting very close to that point of saying we can take the difference between us and what is being done in the average out of the equation.” For the latest in situ oilsands projects, the current difference is five per cent, but that will be driven down even faster with the introduction of new technologies, Stringham

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predicted. He said later he was referring to any in situ project with a steam to oil ratio of 2.2 or below, such as Cenovus Energy Inc.’s Foster Creek. “Those technologies won’t revert back,” said Stringham. “Once they’ve got these technologies in place they become the new foundation, so we can take the spectrum of greenhouse gas footprints from all the different oils coming into North America and we can consider the ambition of the industry to be equal to, if not better, than those that are out there,” he said. While CAPP believes that is a technologically achievable goal, it will be up to oilsands companies to develop those new technologies, according to Stringham. In his presentation, he suggested that to be able to obtain the market access that is so crucial, the industry needs to be able to communicate how it is responding to environmental concerns. “We are judged by our environmental performance and we clearly need to demonstrate that improvement.”

West Ells SAGD project costs climbing Sunshine Oilsands Ltd. says it has undertaken a detailed review of its cost estimate and schedule for the West Ells steam assisted gravity drainage project, currently under construction near Fort McMurray, after concluding the project will experience higher costs and minor delays. Total (Phases 1 and 2) direct costs at West Ells are now estimated at approximately $496 million, excluding the road and further contingencies, a $28 million increase from an earlier installed cost estimate of approximately $468 million, excluding contingencies and $30 million for the shared, multi-project main access road. The revised figure is based on its revised cost and presentation format, with certain expenditure items now allocated to other areas of investment or cost categories, said Sunshine. The anticipated date for first steam injection has also been pushed back from the third quarter, as previously scheduled,

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JUNE 2013 • OIL & GAS INQUIRER

to late in the third quarter or early in the fourth quarter. Drilling of the fi rst eight well pairs for the 5,000-barrel-per-day Phase 1 is now complete, with well completions under way. The drilling rig will now move to the second well pad required for the additional 5,000-barrel-per-day Phase 2, which is scheduled to be brought online in the fi rst quarter of 2014. Approximately 75 per cent of the piles have been set for Phase 1, with pilings expected to be completed by the end of May. Module procurement is well under way, with five modules completed and the balance of Phase 1 modules under construction. Field constructed storage tanks are 60 per cent complete. About 80 per cent of the operations team has been hired and is expected to move to the site over the next two months to assist with facility turnover, commissioning and start-up.

Northeastern Alberta

With the currently anticipated cost increases, and after allowing for expenditures for costs and investments in other categories of activity, Sunshine forecasts its 2013 overall capital needs to grow by approximately $30 million. That estimate assumes certain investments relating to development of future projects will be deferred if necessary. Overall funding for 2013 and 2014 will continue to come from a combination of cash on hand, borrowing and potential joint ventures, as well as revenue from early stage production from West Ells in 2014. Sunshine intends to use the company’s revolving credit facility of up to $200 million as a source of funding, with availability and size subject to meeting certain tests. Sunshine has notified its lending group of the increased capital cost at West Ells. The company said it continues to monitor markets to optimize its sources of funding. — DAILY OIL BULLETIN

Canadian Natural bullish on heavy oil differentials By Pat Roche

Canadian Natural Resources Limited (CNRL) is bullish in its outlook for heavy oil differentials through the rest of this year, shareholders heard in early May. “We are very bullish on heavy oil pricing in 2013 as well as the mid- and long term,” president Steve Laut told the company’s annual meeting in Calgary. “There is significant heavy oil conversion capacity coming on stream in PADD II and significant current underutilized heavy oil refi ning capacity in the Gulf Coast. And we see the infrastructure constraints to get to the Gulf Coast being removed.” He said the company’s expectations for heavy oil differentials have been correct so far in 2013 with the differential reducing from 35 per cent in January to 15 per cent in May, and it is likely to be 18 per cent for June. “We expect 2013 to be somewhat

volatile with differentials averaging about 20 per cent for the rest of 2013.” “Although there will be some headwinds for light oil production to access markets, we believe these are manageable” Laut said. “Cushing is on its way to being debottlenecked which will reduce the [Louisiana Light Sweet–to–West Texas Intermediate, or LLS-to-WTI] differential.” While CNRL expects North American light oil production to keep increasing, it also anticipates improvements in Alberta’s access to North American refi neries—fi rst via rail and ultimately via pipeline. “Since the debottlenecking at Cushing, we have seen the Brent-to-WTI differential narrow from roughly $25 to roughly $10 today. We ultimately expect the differential between [LLS] and WTI to be about the cost of transportation between Cushing

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Northeastern Alberta

and the Gulf Coast—which is around $5 a barrel,” he said. Replying to reporters’ questions after the shareholders meeting, Laut didn’t appear worried about a recent doubling of U.S. crude exports to Canada.

per cent

Canadian Natural Resources Limited’s expected heavy oil differential for 2013

U.S. crude oil exports to Canada nearly doubled to 124,000 barrels per day in February, the highest in 13 years, U.S. Energy Information Administration data showed in early May. The shipments, which are an exception to U.S. laws that otherwise prohibit exports of U.S. crude oil, have been

slowly rising in recent months as eastern and Atlantic Canada refiners tap into the shale oil boom with rail or tanker deliveries. Last year, Canada imported about 60,000 barrels per day of crude from the United States. “I think that’s a sign of the times,” Laut said. “It makes sense. If you look at the refineries that are importing it...they’re all light oil refineries. So they need light oil. And mostly the source of their light oil is Brent priced. So it makes sense for them to buy WTI-priced oil versus Brent. So it just makes good economic sense. We don’t have any issue with it.” But should Canadian oil producers be worried, given that Canada is a net oil exporter and the United States is a net importer, yet the United States is increasing its exports into Canada? “It’s all a matter of which is the shortest transportation route,” Laut said. “So there’s light oil being imported into the United States from Canada, there’s some light oil going to eastern Canada from the United States, and there’s light oil from Canada going—most of it by rail—to refi neries in New Brunswick and Quebec.”

Devon pilot project at Jackfish 1 aims to improve productivity Devon Energy Corporation is testing a variety of productivity enhancements at its Jackfish 1 thermal oil project including the use of solvents and natural gas co-injection. “Our first pilot program on these new fronts kicked off in the first quarter. If successful, these technologies will likely apply to our other thermal assets,” Dave Hager, executive vice-president, exploration and production, said in a first-quarter conference call. “We will be monitoring the results of this pilot program over the course of the year to determine the degree of success and the optimal path forward regarding their use at other locations.”

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Hager noted that the company expects payout at Jackfish 1 to be achieved later this year. “The exact timing of payout at Jackfish 1 continues to fluctuate with changing heavy oil prices and differentials, but our current expectation is for payout to occur sometime in the second half of this year,” he said. John Richels, president and chief executive officer, said that while he expects price volatility to persist for at least the next 12 months, he’s pleased with the recent recovery in Canadian heavy oil price realizations. “Western Canadian Select blended pricing has dramatically improved from a low of approximately 50 per cent of West Texas Intermediate [WTI] in mid-January to as high as 85 per cent of WTI in recent weeks,” he said. “As with changes to natural gas pricing, our leverage to higher Canadian heavy crude pricing is quite meaningful.” Meanwhile, net production from the Jackfish 1 and Jackfish 2 oilsands projects averaged a record 54,000 barrels of oil per day in the fi rst quarter of 2013, an 18 per cent increase in production from the same period last year. Jackfish 1 contributed 33,000 barrels per day, while Jackfish 2 produced 21,000 barrels per day. Hager said the company recently completed an additional well pad at Jackfish 2. “Installation of pad facilities will continue through the summer followed by commissioning and fi rst steam scheduled for late in the fourth quarter,” he said. Hager said that construction of Devon’s third Jackfish oilsands project is now approximately 60 per cent complete, with start-up expected by year-end 2014. At Pike, a Devon operated 50 per cent joint venture with BP p.l.c., Hager said the winter drilling program was wrapped up in the first quarter with the company drilling 34 core wells and acquiring 55 miles of seismic. “This program essentially completes the evaluation of the first phase of the Pike development, confirming a high-quality reservoir similar to that of our Jackfish projects,” he said. Devon expects to receive regulatory approval for Pike by year-end and is continuing work with BP on the design of the 105,000-barrel-per-day development. Adjusting for this non-cash charge and other items securities analysts typically exclude from their published estimates, the company said it earned $270 million in the first quarter of 2013.

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CENTRAL ALBERTA WELL ACTIVITY APR/12

APR/13

Wells licensed

102

APR/12

APR/13

Wells spudded

APR/12

APR/13

Rigs released

▼

Source: Daily Oil Bulletin

C.A.B. Central Alberta

DeeThree reports 1,580-barrelper-day Belly River oil test

Photo: Aaron Parker

A four-day production test of DeeThree Exploration Ltd.’s most recent Brazeau property horizontal Belly River oil well resulted in a fi nal rate of about 1,580 barrels per day of oil and, as a result of successful drilling in the first quarter, the company is reviewing its 2013 capital program. In late April, DeeThree announced the well continued to flow for four days up the 11.4-centimetre frac string at an average rate of 1,770 barrels per day of 44 °API reservoir oil and 1.6 million cubic feet per day of natural gas, with the fi nal rate of 1,580 barrels per day of oil and 1.8 million cubic feet per day of natural gas (on a 3.8-centimetre choke at a wellhead pressure of 40 pounds per square inch). With expected conservation of produced natural gas for sale, this fi nal test

rate equates to approximately 1,920 barrels of oil equivalent per day (88 per cent oil and liquids). Final water cuts at the end of the test period were approximately 12 per cent. The 100 per cent DeeThree-owned well was drilled to a planned total depth with a horizontal lateral of about 2,000 metres in upper Belly River sand. The horizontal lateral was successfully fracture-stimulated, placing 550 tonnes of sand over 19 stages using an energized water-based system. The well is currently shut in for pressure work, and the company began operations to tie the well into the existing pipeline and facility infrastructure. With the well announced, DeeThree has drilled 18 Belly River horizontal wells in its Brazeau property, where it has more

than 70 sections of high working interest Belly River lands widely spread throughout the land base. As a result of a successful drilling program in the first quarter of 2013 and expected production gains, DeeThree is reviewing its capital program with the intent of further accelerating exploitation of its Brazeau Belly River property and its Ferguson Alberta Bakken property. With an original 2013 capital program of about $150 million, in February DeeThree announced its 2013 production

The horizontal lateral was successfully fracture-stimulated, placing 550 tonnes of sand over 19 stages using an energized water-based system.

forecast at approximately 6,800–7,000 barrels per day with a targeted exit rate of 8,500–9,000 barrels per day. The company has proven significant productivity in six different distinct intervals within the Belly River zone. Further, production results have continued to improve due to DeeThree’s rapidly increasing geotechnical understanding of the Belly River zone and improving drilling and completion techniques. DeeThree has now initiated a resource evaluation over its Brazeau Belly River lands. The company’s Brazeau drilling inventory continues to increase and DeeThree now has over 100 horizontal drilling locations in inventory on its Belly River land base as a result of the success of its horizontal drilling program and the well control provided by historical vertical wells. DeeThree Exploration Ltd. has drilled 18 wells in its Brazeau Belly River play, with 100 horizontal targets identified.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • JUNE 2013

Central Alberta

Talisman announces Duvernay drilling results Talisman Energy Inc.’s first well on its southern Duvernay lands yielded about 1,000 barrels of liquids per million cubic feet of natural gas. The company says it has a total of 350,000 net acres in the Duvernay formation, an emerging shale play in northwestern and west-central Alberta that is generating excitement as a potential analogue to the liquids-rich Eagle Ford play in Texas. Industr y activity has been mostly focused in the northern Duvernay where more than 100 wells have been drilled with encouraging results. But last year Talisman began appraisal activities in the relatively under-explored and under-appraised southern Duvernay near Willesden Green, said Paul Smith, executive vice-president of North American operations. “We hold...the largest single position in this part of the play with 189,000 net acres of land positioned in what we now believe to be the richest portion of the condensate and volatile oil windows,” Smith told analysts. Talisman’s Duvernay drilling results and its plans to seek buyers or jointventure partners for vast swaths of its North American gas resource base—including the Montney and northern Duvernay— were announced at the company’s investor open house in Toronto. The company estimates it has a prospective resource of 600 million barrels equivalent on its southern Duvernay land, where it has now drilled three and completed two wells, Smith said.

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“Our first well, the 11-03 well in the southern Duvernay, was completed with a relatively short lateral of only 3,500 feet, with only five effective frac stages,” he said. However, the 11-03-041-05W5 well had a 30-day initial production rate of about 300 barrels per day of condensate (50 ˚API oil) and a total liquids yield that

topped 1,000 barrels per million cubic feet of gas, Smith announced. Not surprisingly, Talisman will hang onto its southern Duvernay lands, but will seek buyers for some or all of its North Duvernay acreage, which has also produced strong results. “Our second southern Duvernay well, the 02-06 well, which is slightly to the northwest of the first well, has only been tested in the last few weeks—again with a relatively short lateral of 3,500 and only seven stages completed,” Smith told analysts. During its first seven days of production testing, Talisman’s second well (0206-042-05W5) in the southern Duvernay flowed 1.1 million cubic feet a day of gas with a condensate yield of 110 barrels per million cubic feet, he said. A third well has been rig-released but not completed. Smith said Talisman is currently drilling its fourth well into the southern Duvernay and expects to bring another two or three wells on stream in the southern portion of the play this year. He said the company is developing plans for a phased development scheme for the southern Duvernay, starting next year. In the northern Duvernay, meanwhile, Talisman has about 159,000 acres in the Kaybob area with a prospective resource of 800 million barrels equivalent, Smith said. So far, the company has drilled three pilot wells on its northern Duvernay lands. Each well was completed with an average of only six stages per well—the wells are relatively short because they’re in pilot phase.

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JUNE 2013 • OIL & GAS INQUIRER

Photo: Joey Podlubny

By Pat Roche

Central Alberta

Smith said the three pilot wells resulted in an average 30-day initial production rate of 3.2 million cubic feet per day and 60 barrels per day of field condensate. “In addition, we would expect to see, on average, an additional 290 barrels per day of NGLs [natural gas liquids] from each of our three pilot wells processed through a deep-cut facility,” he said. “Put another way, we estimate that an optimized development well in our pilot area, drilled with a 5,000-foot lateral and completed with 12 stages, would result in a well of approximately 6.5 million cubic feet a day of gas and 700 barrels a day of condensate and NGLs.” Despite the stellar results, Talisman plans “to divest all or a portion of” its stake in the North Duvernay, said chief executive officer Hal Kvisle. Smith said the decision is part of the company’s effort to focus its North American portfolio in the near term: “We intend to commence a process to dilute our North Duvernay position—preferably through an outright sale.” Kvisle told analysts and reporters that Talisman’s North American gas acreage is too much to develop on its own. “We simply are not a large enough company, we do not have the financial resources,” the chief executive said. The statement that Talisman—with average fourth-quarter production of 392,000 ba r rel s equ iva lent per day— i s too small to develop all its lands indicates the vastness of its holdings and cost of development.

Talisman’s Montney acreage, which is in northeastern British Columbia, holds the biggest single chunk of its resource base. Kvisle said the company will consider two options for its Montney lands. One would be a complete exit from the play. He said the other option may be to sell or form joint ventures on “one or two” of its three main Montney areas. He estimated the company’s entire Montney acreage is wor t h bet ween US$2 billion and US$4 billion. Smith noted Talisman’s 2013 capital budget of $1.1 billion for North America is half of what the company was spending in the region two years ago when gas prices were higher. In recent months, the company curtailed spending in the huge Marcellus shale gas play in the northeastern United States. “I want to emphasize this should not be seen as a negative reflection on the Marcellus property,” Kvisle said. “I’ve seen few properties in my career that have the quality and predictability of our Marcellus gas. But at this point in the gas price cycle, it’s important that we pull back.” Smith said Talisman has reduced Marcellus spending to the minimum needed to honour lease obligations and protect core acreage: “This works out to be about $150 million per annum. This year we will allow approximately 10,000 non-core acres to expire and will end the year with around 200,000 net acres in the Marcellus.” The company expects to bring on only 18 net wells in the Marcellus this year.

Alberta regime helps Duvernay development By Elsie Ross

The emerging liquids-rich Duvernay shale play in west-central Alberta is ideally situated when it comes to development, an unconventional resources conference heard recently. “If we could pick up the Duvernay and move that reservoir to wherever we wanted to in North America, my thinking is we would put it exactly where it is,” Brendan McCracken, Duvernay team lead for Encana Corporation, told the Hart Energy and CSUR 2013 DUG Canada conference in Calgary. In his presentation, he outlined four cornerstones of the play: the Alberta government’s fi scal and royalty incentives, a surface environment suited to a resource play hub, access to infrastructure and the service sector, and structural demand for the pentanes plus it produces. The deep gas holiday and the shale new well program are a “huge leg up,” according to McCracken. “On an after-tax afterroyalty basis, the Duvernay actually winds up delivering superior returns to some of its sister peer plays in the United States,” he said. While plays such as the Eagle Ford in Texas deliver much better returns than the Duvernay on a cost basis before tax and royalties, “when you factor in those taxes and royalties, which is after all, reality, the Duvernay delivers superior returns.” A second cornerstone is the surface environment that is suited to what Encana

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calls a resource play hub with the use of pad drilling and long-reach horizontal wells. “It’s not so far west it’s in the mountains, but it’s not so far east it’s in populated areas,” said McCracken. “It’s kind of situated in this perfect little surface fairway where the environment is perfectly suited to having rigs and spreads sitting on pads for long periods of time.” As the massive liquids-rich play fairway is in an area that has been active for 60 years with conventional oil and natural gas plays, it also has access to a well-developed service sector and unutilized infrastructure capacity. Additionally, in Alberta the condensate is in high demand for use as a diluent for bitumen. The three main areas of the Duvernay are Kaybob, Edson and Willesden Green. “The intention was to secure big positions in the hearts of those areas and that’s what we went out and did,” said McCracken. Although companies have spent a total of more than $4 billion in the Duvernay play, about $2.57 billion has been spent on about 3.1 million acres in the high-grade liquids fairway where land went for a maximum of $6,051 per acre, the conference heard. Encana, which has 460,000 gross acres and spent a fraction of that, has got a great position, he said. “By all accounts, we have control over half of the high-grade fairway in the liquids-rich window; it’s a great place to be.” In most Duvernay wells that Encana has observed, a little over 80 per cent of the C3+ mixture is condensate, with 75 per cent of that field condensate and another five per cent C5+ processed at the gas plant, said McCracken. “Contrast that to other liquids-rich plays where you are lucky if you get half of your C3+ mixture as condensate,” he said. “When you consider that condensate is trading at about a $14 [per barrel] premium to WTI [West Texas Intermediate], that’s a pretty good news story from a commercial standpoint.” The company has seen anywhere from single digit barrels per million cubic feet yields all the way up to 400 barrels per million cubic feet. Nor does maturity have anything to do with it, said McCracken. “You can look at wells that are making a 100 barrels per million and go down dip onto Encana land and make 300 barrels per million and that doesn’t really happen in any of the other liquids-rich plays in North America.” Encana currently has two rigs actively drilling and so far has drilled 10 gross wells (eight horizontal and two vertical). Four horizontal wells are producing and one is waiting for tie-in, one for completion and two are shut in for active pad completion. According to McCracken, Encana has drilled the three longest horizontal wells in the play. The Ferrier 12-04-42-8W5 well has a 7,280-foot (2,200-metre) lateral and was completed with 23 frac stages and registered 50 barrels of condensate per million cubic feet. The 24-hour test was 6.5 million cubic feet equivalent per day while the 30-day initial production (IP) was 3.5 million cubic feet. The Saxon 16-5-6224 well has a 4,370-foot (1,324-metre) lateral completed with 12 stages with a 24-hour rate of 12 million cubic per day and an IP-30 rate of 6.4 million cubic feet per day with 200 barrels of condensate per million cubic feet. In response to a question, McCracken acknowledged there is still limited information on how the play will develop. Because Encana has to use spare infrastructure capacity, a lot of its wells are restricted.

Central Alberta

“You wind up finding solutions to get your wells online and on production because that’s the commercial intention of the play, and so you kind of have to ride that restricted flow out,” he said. “We are extremely encouraged from the IPs we have seen in both ourselves and [the] industry.”

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So far, the industry has drilled a total of 95 Duvernay wells (62 horizontal and 33 vertical), with 40 wells (35 horizontal and five vertical) on production. Encana has an estimated 9.1 billion barrels equivalent of petroleum initially in place on its lands and the estimated ultimate recovery is between four and 9.5 billion cubic feet equivalent per well. Late last year, Encana did a joint venture with Phoenix Duvernay Gas, a subsidiary of PetroChina Company Limited, which agreed to invest $2.18 billion, including $1.8 billion upfront, over four years for a 49.9 per cent working interest in the play. There will be an estimated $4 billion total gross investment over that period. This year, gross Duvernay capital investment, including 20 (10 net) wells is expected to be about $600 million, with about $450 million coming from Phoenix. Duvernay shales, considered to be the primary source rock for the Leduc, Slave Point and Keg River reef/pinnacle pools, have a number of attributes that make it very attractive, the conference heard. One is the formation’s 100 per cent organic porosity, a unique characteristic to a shale play in North America. “What that means is that all the porosity that exists in Duvernay shale in the evaluations that Encana has done has been completely dry with kerogen and that sets up some really interesting behaviours that are going to govern how the play produces,” he said. Another attribute of the formation is that it is extremely over pressured. “It’s an environment where depth is not equal to maturity, which has been a very important factor in assembling land positions,” said McCracken. “Encana cottoned on to that fact very early on.” In addition, the rock is extremely frackable when it comes to stimulations and as a result it’s possible to create a lot of complexity and additional permeability in the play, he said.

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Central Alberta

Cardium boosts PetroBakken production By Paul Wells

PetroBakken Energy Ltd. fi rst quarter production averaged 49,078 barrels equivalent per day (82 per cent light oil and liquids), an increase from 46,772 barrels per day during the comparable period last year. The growth in output can be primarily attributed to the successful execution of the company’s drilling program in the Cardium, as well as optimization activities on existing wells in Saskatchewan that continue to mitigate production declines. The liquids weighting of PetroBakken’s production has slightly decreased to 82 per cent as a result of growth in Cardium production, which has a higher gas/oil ratio compared to the company’s Saskatchewan production, as well as temporary facility restrictions in the Cardium business unit having a proportionately larger impact on light oil production.

“The Cardium is grinding out 20,000–21,000 barrels per day, and we think there’s growth into the mid- to high twenties through 2013 and 2014.” — John Wright , president and chief executive officer, PetroBakken Energy Ltd.

Average production in April was approximately 48,000 barrels per day, based on field estimates. “The fi rst quarter came in right in line with our guidance and internal estimates, and the beginning of the second quarter is running slightly ahead of our expectations,” president and chief executive officer John Wright told the company’s fi rst quarter conference call. “As planned, the first quarter was very active for us and results are right in line with our forecast. We spent 45 per cent of our $675 million capital program in the quarter by drilling 41 per cent of our projected 129 wells for the year.” Funds flow from operations was equal to $178.94 million, off from $187.40 million achieved during the fi rst quarter of 2012. The decline is primarily due to the decrease in realized operating netback. PetroBakken booked first quarter earnings of $1.61 million, down from net income of $18.49 million for the prior year period. Net income was affected by lower realized prices, a foreign exchange loss and higher depletion and depreciation. Revenues were down four per cent year over year. During the fi rst quarter of 2013, the company drilled 53 wells and brought 41 wells on production, which is down from the 79 48

JUNE 2013 • OIL & GAS INQUIRER

Central Alberta

wells drilled and 99 wells brought on production in the fourth quarter of 2012, but up from the 47 wells drilled and 36 wells brought on production in the fi rst quarter of 2012. On Mar. 31, 2013, there were 30 wells waiting to be completed and/or brought on production. Wright noted that a delayed spring breakup has allowed the company to remain active and it anticipates approximately half of the wells in inventory will be brought on production by the end of the second quarter. In southeastern Saskatchewan, the Bakken business unit averaged 19,029 barrels per day of production during the fi rst quarter of 2013, which was relatively flat to fourth quarter 2012 production of 19,741 barrels per day. The company remained active in the Bakken throughout the fi rst quarter, resulting in 15 wells drilled and 14 wells brought on production. “In the Bakken business unit, maturing production, along with drilling and well optimization activities, has resulted in the stabilization of production from the fourth quarter of 2012 to the fi rst quarter of 2013,” senior vice-president and chief operating officer Rene LaPrade said. “Through future drilling and optimization of our extensive inventory of existing wells, we expect to continue to mitigate production declines and generate free cash flow in this business unit.” In Alberta, production continued to grow in the Cardium business unit, with the majority of first quarter 2013 activity occurring in the West Pembina area. Production in the quarter averaged 20,614 barrels per day, which represents an eight per cent increase over fourth quarter 2012 and a 24 per cent increase over fi rst quarter 2012. Throughout the quarter, there was approximately 600 barrels per day of production restricted in the Lochend region due to facility constraints. During the first quarter, PetroBakken drilled 23 Cardium wells and brought 17 wells on production, leaving an inventory of 22 wells waiting to be brought on production at Mar. 31, 2013. “The Cardium is grinding out 20,000–21,000 barrels per day, and we think there’s growth into the mid- to high twenties through 2013 and 2014,” Wright said. “Our plan would be to see us level-loading that production rate in the high twenties or low thirties for a very long, extended period of time and make the best use of any infrastructure buildup that we’ve done, not unlike the Bakken, which has turned into a 19,000–20,000-barrel-per-day cash cow for us.” In the company’s Alberta/B.C. business unit, production in the first quarter of 2013 averaged 3,362 barrels equivalent per day, representing a 21 per cent increase over fourth quarter 2012. During the quarter, PetroBakken drilled eight wells in this business unit, brought two wells on production and suspended two wells, leaving an inventory of four wells waiting to come on stream. Production additions in the Swan Hills region have increased the overall liquids weighting of this business unit to 47 per cent, up from 40 per cent in the fourth quarter of 2012. The company said its southeastern Saskatchewan conventional business unit continues to provide a low decline, light oil production base. PetroBakken drilled seven wells in the business unit in the first quarter and generated average production of 6,073 barrels per day.

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Gibson adding storage tank at Hardisty Gibson Energy ULC says it has received committed customer support for an additional 500,000-barrel crude oil storage tank at the company’s Hardisty terminal. The new tank will be constructed on Gibson’s eastern Hardisty lands along with the two 400,000-barrel tanks announced in September 2012 and the 300,000-barrel tank (now revised to 400,000 barrels) announced last month. Site preparation and civil work on the eastern Hardisty lands is now underway, and the fi rst 400,000-barrel tank is

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Additional oil storage capacity announced by Gibson Energy ULC

expected to be in service in mid-2014 with a late 2014 in-service date for the second and third 400,000-barrel tanks. The 500,000-barrel tank has an expected early 2015 in-service date. “The addition of 1.7 million barrels of new storage capacity announced in the last seven months reaffi rms the attractiveness of our Hardisty terminal location for customers as they direct their current and future production to appropriate markets,” Rick Wise, Gibson’s senior vice-president of operations, said in a news release. The company continues to have positive discussions with several customers regarding the further build out of strategic land positions at its Hardisty and Edmonton terminals, he said. “Therefore, we expect nearterm organic growth to be largely driven by long-term, fee-based contracted storage tank construction, expanded terminal services and construction of rail infrastructure to facilitate crude oil movements.

SOUTHERN ALBERTA WELL ACTIVITY APR/12

APR/13

Wells licensed

APR/12

APR/13

Wells spudded

APR/12

APR/13

Rigs released

▲

▼

Source: Daily Oil Bulletin

S.A.B. Southern Alberta

Alberta shelving shallow rights reversion plans By Richard Macedo

Photo: Joey Podlubny

Alberta’s recent announcement that it was indefinitely shelving serving shallow rights reversion (SRR) notices for petroleum and natural gas agreements issued prior to Jan. 1, 2009, drew applause and some disappointment, according to responses from some industry representatives. In a statement, the Canadian Association of Petroleum Land Administration said it was “extremely pleased” with the decision by Alberta Energy to put an indefinite hold on the issuance of SRR notices.

Low gas prices have destroyed shallow gas drilling.

“Overall, it’s a favourable decision for the oil and gas industry based on projected costs, manpower and exploration programs that these notices would have created,” the group stated. In past discussions about SRR, critics have argued that severing different layers of subsurface mineral rights beneath the same land parcel not only encourages more drilling, but also the construction of surface facilities—such as compressors, plants and pipelines—that would otherwise not be built. Proponents of SRR have argued that it often means faster development of oil and gas reserves, since the failure to develop shallow resources would typically cause their reversion to the provincial Crown for later resale to other oil and gas companies. Troy Winsor, investor relations representative with Bellatrix Exploration Ltd., said the decision is a positive one. “Industry players, including Bellatrix, have invested significant capital into drilling wells to evaluate and prove up potential resources on lands acquired through mineral leasing,” Winsor said. “Typically, companies initially target the completion and tie-in of zones that have been deemed most economic to do—those that provide an acceptable rate of return on initial invested capital.” In many cases, the up-hole shallower reservoir zones have lesser economic impact due to smaller recoveries and lower liquid yields. “Bellatrix sees these shallow zones— pr e dom i n a nt l y lowe r-pr e s s u r e g a s assets—as f uture resources that the company can develop when gas pricing improves,” Winsor said, adding that the

current decision by the government will also save significant industry and government manpower and capital that would be consumed in the preparation and evaluation of the multitude of technical submissions that would be required by most of the industry players in the basin to make an application for continuation. “The cost component of re-completing potentially uneconomic shallower hydrocarbon zones, and the loss of revenue

“Overall, it’s a favourable decision [to shelve the issuance of shallow rights reversion notices] for the oil and gas industry based on projected costs, manpower and exploration programs that these notices would have created.” — Canadian Association of Petroleum Land Administration

resulting from the temporary suspension of deeper productive zones to do so, has been essentially reallocated by the government through the ruling, back into the most economic horizons.” The news has an overall positive impact on the company, Winsor said. It enables Bellatrix to continue to focus on the continued development of its economic inventory in the Cardium and Notikewin/Falher oil and liquids-rich gas plays. “Only a small percentage of the company’s leases were acquired post-2009; these will be handled as leases approach expiry,” he said. Glenn Gradeen, president and chief executive officer of Tangle Creek Energy Ltd., said he was disappointed by the news. OIL & GAS INQUIRER • JUNE 2013

Southern Alberta

“I think you do have to be respectful of the current folks that own the shallower rights,” he said. “I think you can accommodate and phase it in over time and handle it properly. “I think what’s happened is the government’s sort of in a position where nobody moves, nobody gets hurt. But that’s not the right thing, I think, for Albertans,” Gradeen added. “Nine times out of 10, when a company is looking at a prospect or bidding on some rights, they have a specific idea in mind and they drill down. “We’d all like to have the shallower rights and it gives you opportunities for serendipity...but at some point or another, if you have success in the deeper horizon, then those [shallower] rights become stale, and there’s no motivation for the current owner to do anything with it, he can just sit on it.” Gradeen added SRR would create good opportunities for the smaller companies. “It’s doable; maybe you phase it in over five years and maybe the first several years, it’s just a process whereby it’s not happening automatically, it’s happening when people request it,” he said. “I think it can be done; we’ve got a lot of electronic systems. It’s going to take some additional human resources, there’s no question, but there would be a net benefit to the province.” There would likely be more interest in SRR if natural gas prices were higher, he added. “I think this would be beneficial on an overall basis to Alberta and to revenues to the province,” Gradeen said. “However, I do recognize the big guys have [petroleum and natural gas rights]; they bought the access to the rights under one set of rules and now [we would end] up changing them. “Clearly, anybody with a serious land position is not going to like [SRR],” he noted. “Anybody that already has a lot of land isn’t going to like it because they have the [option] of being able to sit on it right now. And anybody that’s trying to build a business probably wants it. “I think it can be done in a respectful and a careful way, and in such a fashion that it wouldn’t be too hard on anybody.” 54

JUNE 2013 • OIL & GAS INQUIRER

ERCB denies Cardium wells, multi-well battery in Lochend area By Elsie Ross

An application from a Calgary oil and gas company to drill two sweet oil wells and to construct and operate a multi-well battery in the Lochend area has been refused by the Alberta Energy Resources Conservation Board (ERCB). Bernum Petroleum had applied to the ERCB for licences to drill two new pool wildcat Cardium wells and to construct and operate a multi-well battery at either a surface location at 01-04-026-03W5 (01-04 surface location) or an alternative surface location at 16-33-025-03W5 (16-33 surface location), about 4.7 kilometres east of Cochrane, Alta. The two horizontal wells would be drilled to projected bottomhole locations at 16-04026-03W5 and 01-33-025-03W5. In a decision following a public hearing late last year, the board denied the battery

narrowly as two exploratory wells, as applied for, or to include consideration of the broader issues of project development and potential surface development. The multi-well facility equipment was to consist of two separators, four liquid storage tanks, a flare knockout tank and a flare stack. The landowners of the proposed surface locations, Timothy and Frances Bancroft, had objected to any proposed wells and the facility on their lands as they could potentially affect future country residential development plans. Several other residents in the Meskanaw and Glendale communities also filed objections. According to the decision, Bernum said it planned to flare or incinerate the produced gas from the applied-for wells and anticipated using an incinerator during the well completion, cleanup and testing phases. The company also The Alberta Energy Resources Conservation Board, indicated that though, said it was “not convinced” that gas at the Bancrof ts’ request, it would conservation is uneconomic. Based on the economic consider using an runs provided by Bernum Petroleum in its application incinerator during n or m a l p r o duc and in the board’s undertaking, the panel found that t ion oper at ion s. Bernum could generate a positive net present value. However, it said, it would need the battery licence so that application on the basis that a flaring batit could produce its first well before drilling tery is “not acceptable” when it would be the second well. Conservation of the gas is not economic economic to conserve the associated gas, and the facility would be in an area with at this time given the estimated volume of a high probability of country residential produced gas, the expected price of gas, development. the cost associated with possible tie-in The well applications were denied with locations and the recoverable resources, according to Bernum, which said it would the majority of the three-member panel fi nding that the applications failed to connot drill the wells if it were required to consider the full development of the project. serve the gas. “Given that the fl aring facility is denied, Bernum said it holds a freehold minthere were alternative sites that would eral lease for section 33 and a Crown minhave less overall impact for this and future eral lease for section four. It also holds a development and would better meet the freehold mineral lease for section 31 and public interest,” said the board. a combination of Crown and freehold lease However, the board said its panel disfor the northwestern quarter of section 28 agreed over whether to assess the applications in the Lochend field.

Southern Alberta

The company hopes to drill follow-up wells, tie in the produced gas sometime in the future and make the whole project (i.e., the full development of its mineral holdings in sections 33-025-03W5 and 04-026-03W5) more economic. It assessed the economics of tying in the gas based on a two-well scenario and not on a projectbased case. According to the decision, Bernum said it needs to drill, complete and test the initial well before it makes any future plans. Since there is currently no production information from the immediate area and the proposed wells are exploratory, it had to make assumptions and consider the worst-case scenario for the gas production rates used in its economic evaluation. The board, though, said it was “not conv inced” that gas conser vation is uneconomic. Based on the economic runs provided by Bernum in its application and in the board’s undertaking, the panel found

that Bernum could generate a positive net present value. The board also found that the use of an incinerator during the completion, cleanup and testing phases would mitigate potential concerns about visual aesthetics and noise usually associated with temporary use of a flare stack. The proposed wells are considered exploratory because they are outside an established pool or field at the southern end of the Lochend Cardium trend. Only five wells, including three in the 1960s, have been drilled as oil wells deep enough to evaluate the Cardium, according to the company. In its decision, the board said Bernum considers all of sections four and 33 to be within a mapped “sweet spot” based on the five-metre contour of greater than 25 ohmmetres resistivity response. Bernum said it planned to drill the 16-04 bottomhole location first and contingent

upon the testing results proposed to produce the well for six to eight months to understand the potential reserves. If successful, it would then drill the well to the 01-33 well bottomhole location and if the proposed wells proved to be economic, it intended to drill the western halves of sections four and 33, according to the decision. As Bernum planned to flare or incinerate the produced gas from the proposed wells, it reviewed potential alternative surface locations using the 500-metre setback from existing residences as required by the ERCB. In its decision, the board said the Bancrofts maintained that Bernum’s assessment of alternative surface locations was deficient because it had not completed a full area development plan that would factor the location of future wells into its applications. Bernum, though, contended that it would be irresponsible and meaningless

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Southern Alberta

to prepare a development plan at this stage with so many unknown variables, emphasizing that it did not have plans to drill additional wells at this time and that any future drilling would be contingent on successful production from the two exploratory wells. However, the company acknowledged that based on the current spacing unit in the Lochend Cardium field, it could be drilling up to four wells per section or a total of eight wells for the two sections for which it holds the mineral rights. It also said it would require another surface location as it would not be able access its minerals in the western halves of sections four and 33 from the proposed surface locations. Bernum also said that all eight wells could be drilled from a single pad site near the existing radio tower in 02-04-02603W5, but discarded the site given the proximity to the Meskanaw and Glendale communities and the initial negative responses it received from residents. The majority of the panel found that the company could drill the two applied-for bottomhole locations from a site that could also accommodate future development drilling,

especially given that the board was denying the applications for the facilities with their associated f laring. “The majority finds that Bernum failed to consider the possibility of future wells and the impact those would have on the number of sites required on Bancrofts’ land,” said the board in its decision. The majority also stated that in this case, it is necessary to understand the full extent of Bernum’s project on sections four and 33 so that it can consider the impacts on the landowners, the residents and the community before making a decision on an application. However, the panel member in the minority on that issue said that due to the exploratory nature of the proposed wells, a full consideration of a development plan may not be possible at this time, and that the board, in considering the application, need not take into account the impacts of future potential development wells. “The minority is of the view that if Bernum were to provide a development plan without information on the two proposed exploratory wells, such a plan would be of limited assistance in

determining the need for future wells and associated surface locations for future wells or other infrastructure,” according to the decision. In the view of the minority panel member, approval of the well licences would facilitate drilling and the evaluation of Bernum’s mineral interests and would provide the actual production figures necessary for the company to determine its future development plan. If the proposed wells proved successful, Bernum would gain information about the pool and any future developments that may be required, said the dissenting panel member. “At that time, Bernum would be expected to create a more comprehensive development plan and conduct the required consultation before proceeding with future well applications for consideration by the board. “If the wells are unsuccessful, drilling and completion at the 1-4 [01-04-02603W5] surface location will have minimized the noise, dust, visual and general disturbance impacts to the Glendale/ Meskanaw and other area residents.”

Forecasts for gas too bearish, says consultant A Calgary consultant has some advice for oil and gas companies: avoid the herd mentality. Just as the market was still forecasting continued high natural gas prices in 2008 in advance of the recession and the shale gas revolution that drove down prices, now it is missing signals that point to a gradual price recovery, Chuck Baumgart, president of Middleton Energy Management Ltd., told a recent seminar on thriving in an over-supplied Canadian energy market. While the market was too optimistic in December 2008 when the forward curve for 2013 was just under US$8 per million British thermal units, it’s now too pessimistic in the longer term, he said. With the current five-year term price deck of US$4.50 per million British thermal units on the NYMEX ($4.30 NYMEX for 2014) and a five-year price of $4 per gigajoule at AECO, the market is extrapolating current conditions, but once again it’s missing something, said Baumgart. “Are they factoring in environmental approvals? Are they factoring in increased demand?” he asked. “That doesn’t seem to be the case because if you factored in some of those the price deck would be higher.” There is currently resistance to gas at $5 per million British thermal units but once it breaks that barrier, “I can guarantee it’s going 56

JUNE 2013 • OIL & GAS INQUIRER

With high oil prices, it will take a substantial increase in gas prices to get operators to drill, said Chuck Baumgart, president of Middleton Energy Management Ltd.

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to go higher,” said Baumgart, who sees prices gradually rising to the $5 to $6 range with spikes to $8 over the next three to four years. At current prices of under $4 per million British thermal units, natural gas drilling will stagnate because gas producers will not be able to afford to drill new wells, he suggested. In the shale gas plays, the low-hanging fruit is already being picked as the most attractive targets are being drilled up, which means that future gas will require a higher price. Another factor is the low cost of North American gas of about $4 per million British thermal units “compared to a price of between $8 and $11 in Europe and $12 to $15 per [million British thermal units] in Asia, in which gas is priced off the global price of oil, currently about $100 per barrel. “Something’s going to have to happen,” he said. Either the U.S. government permits liquefied natural gas exports or American companies continue to bring manufacturing back to the United States to take advantage of low gas prices. The United States is currently a low-cost producer of petrochemicals, steel and fertilizer, and the longer regulators take to approve exports, the more manufacturing will be repatriated, according to Baumgart, who organized the seminar as a fundraiser for the Kidney Foundation of Canada. “Either way, demand increases and prices rise.” In the past year, gas was trading at prices last seen in the 1993-97 period, with an extremely warm 2011/2012 winter that resulted in unprecedented levels of gas still in storage heading into the summer of 2012, he said. The low gas prices, though, prompted power companies to switch to gas requiring three billion cubic feet per day of supply. However, supplies are beginning to tighten, according to Baumgart. With a more normal winter for 2012/2013, the storage surplus disappeared in five months and inventories are now below the five-year average, he said. By the start of the new withdrawal season November 1, about 800 billion cubic feet of extra gas (4.4 billion cubic feet per day) will be needed to refill storage. “We have a big hole to fill,” said Baumgart. However, only about two billion cubic feet will be available due to a near-term supply decline, he said. That assumes three billion cubic feet per day is available due to power producers switching back to coal, offset by a production decline of one billion cubic feet per day in 2013. Supply is declining as the natural gas rig count has fallen from 800 rigs in early 2012 to fewer than 400 rigs today. The count of unconnected wells also is declining—in the Haynesville shale, the number has fallen from 650 in January 2012 to 280 at present as operators tie in wells drilled earlier to retain land tenure. “There are not a lot of wells left to connect,” he noted. In Canada, operators in western Alberta with a focus on liquids-rich gas plays face constraints in accessing processing capacity for gas and liquids. The NGTL system is more than 90 per cent contracted and gas can’t be brought on as fast as it once could, according to the speaker. And while it’s believed that companies will once again start to drill for natural gas if the price hits $4, the larger companies have all shifted to oil, Baumgart said later. “When you think about how much money they can make at $100 per barrel, why would they shift to gas at $4; gas is going to have to go higher before there’s a shift back to natural gas.”

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Southern Alberta

And even if companies did want to drill for gas, they’d be hard pressed to do so because equity markets aren’t interested in gasweighted companies, he said. “The day you start seeing equity issues for natural gas producers, that’s the day that the price is high enough that these people can make a reasonable price of return, and so far at the current level that’s not happening.” At the same time, companies that bought gas properties at the height of the market have put them up for sale; about one million acres of Montney lands are now on the block, said Baumgart. “It’s the herd mentality; right now no one’s herding into gas so maybe that’s the time you should be.”

“The day you start seeing equity issues for natural gas producers, that’s the day that the price is high enough that these people can make a reasonable price of return, and so far at the current level that’s not happening.” — Chuck Baumgart, president, Middleton Energy Management Ltd.

On the demand side, the demand for gas from power generators continues to rise as coal-fired power generation faces increasing environmental scrutiny. More than 50 coal plants were closed down last year and new gas-fired generation is being built. Baumgart offered two scenarios for the near-term outlook. Should prices stay at current levels or decline further, it will be difficult for storage to refill to where it should be because drilling will remain low and power generators will continue to switch to gas from coal. As a result, if there are hurricanes in the fall or an abnormally cold winter, there’s a much higher chance of a price spike because there will be less available supply. “You can pay me now or pay me more later.” In the second case, the risk of a price spike is reduced substantially, he said. If storage were to refill to last year’s levels, the increased demand for gas would push up the current summer price deck, driving gas generators out of the market at about $4.50 per million British thermal units. However, there would still be other markets such as petrochemical plants and manufacturers who could pay higher prices and still be paying less than they would be if they were paying international prices for gas, said Baumgart. 58

JUNE 2013 • OIL & GAS INQUIRER

Southern Alberta

Industry levy for ERCB operations up 37 per cent Alberta’s conventional oil and gas sector is facing an increase of 37.66 per cent in Energy Resources Conservation Board (ERCB) administration fees this year after the Alberta government decided board operations will be funded solely by the industry. The industry levy for oil and gas will rise to $112.12 million this year from $81.44 million in 2012, while the oilsands lev y w ill increase by 37 per cent to $39.79 million f rom $29.06 million last year. Coal sector fees are up 13 per cent to $2.49 million f rom $2.20 million. T he total indust r y allocation of $154.4 million for 2013 is up 37 per cent from $112.71 million last year. Upon proclamation of the Responsible Energy Development Act, expected in June 2013, the ERCB will cease to exist and the Alberta Energy Regulator (AER) will take its place. At that time, all ERCB funding will be transferred to support the AER’s operations. In addit ion, t he Ca nadia n A ssociat ion of Pet roleum Producers (CAPP) and the Explorers and Producers Association of Canada (EPAC) have jointly requested that the ERCB’s administration fee process be used to collect $2.38 million to fund broad industry initiatives (BII) that the groups say benefit all of the non-oilsands industry in Alberta. The funds are directed to research and innovation with $2.04 million allocated to environmental research projects and $337,320 to Petroleum Technology Alliance Canada. Consistent with prior years, the ERCB has agreed to this request and includes an additional charge for this purpose in the 2013 oil and gas well administration fee invoices, increasing the adjustment factor used for invoicing to 2.33 from 2.28. Funds collected by the ERCB are passed through to CAPP and EPAC. Payment of the BII is voluntary, and the 20 per cent late-payment penalty does not apply to unpaid BII amounts. The ERCB is not involved in and does not make any decisions regarding the manner in which BII funds are spent or to whom BII funds are disbursed. The ERCB’s revenue requirement affects operator lev y invoices. Other factors also contribute to the fee determination at an operator level, including an increase or decrease in wells or entities within the sector, owner ship transfer and amalgamations, new entrants, and volume fluctuations. Invoices vary according to individual operations and are based on operating statistics for the calendar year. Invoices to operators detailing the fee calculations were mailed Apr. 30, 2013, and payments are due by May 30, 2013. The Energy Resources Conser vation Act authorizes the ERCB to make regulations to levy an administration fee on the sectors that it regulates. The act also authorizes the imposition of a late-payment penalty, which is set at 20 per cent on any portion of the fee that remains unpaid after the due date. The ERCB may also close producing facilities for failure to pay an invoice or late-payment penalty.

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SASKATCHEWAN WELL ACTIVITY APR/12

APR/13

Wells licensed

335

245

APR/12

APR/13

Wells spudded

APR/12

APR/13

Rigs released

▼

Source: Daily Oil Bulletin

S.K. Saskatchewan

Secondary recovery will drive the future of the Bakken By Carter Haydu

Photo: Aaron Parker

While the initial boom in the Saskatchewan Bakken has subsided, it is still a lucrative formation and one that oil and gas experts expect will continue to be productive for many more years—in part due to secondary recovery techniques. “This is one of the better, or among the best, plays in western Canada,” said Don Rawson, managing director of institutional equity research with AltaCorp Capital Inc. Producers are several years into developing the play, he said, and while the rate of growth has slowed, there is still a lot of oil in place that will provide opportunities for many years to come as technological improvements continue to expand the geographical area where it is profitable. The primary region of development has been largely defined, although the edges of the play have grown over time, as improving technology helps make it economic in some of the areas on the fringe, said Rawson. According to Daily Oil Bulletin data, in 2012 operators completed 341 wells in the

Saskatchewan Bakken, including 232 in the Viewfield area in the southeasternmost portion of the province. In 2012, Crescent Point Energy Corp.— the largest producer working the formation—completed 137 wells in the play, while PetroBakken Energy Ltd. completed 94. Other companies producing in the Saskatchewan Bakken include Legacy Oil + Gas Inc., Painted Pony Petroleum Ltd., Cenovus Energy Inc. and Husky Energy Inc. The Bakken is also home to a multitude of smaller producers, each with a handful of wells each. Across t he ent ire Saskatc hewan Bakken, 356 wells were completed in 2011, 517 wells in 2010, 432 wells in 2009, 728 wells completed in 2008 and 300 wells completed in 2007. Crescent Point has been interested in the Saskatchewan Bakken since 2005, with the company’s fi rst major move into the formation coming with the acquisition of Mission Oil & Gas Inc. in early 2007.

Operators completed 341 wells in the Bakken in 2012, including 232 in the Viewfield area.

Since that time, the Bakken has proven extremely profitable for Crescent Point as the company has grown its interests in the region, C. Neil Smith, chief operating officer, said. With 4.6 billion barrels, the Saskatchewan Bakken is the second largest oil in place pool ever discovered in western Canada, he said. However, it is still very much in its early days of productivity, with less than four per cent of oil recovered so far. “It’s a much bigger play than we had anticipated. We knew we were on to something extremely good and it exceeded

2,674 Number of wells completed in the Bakken in the last five years

everybody’s expectations,” said Smith. “When we were getting into the pool we were thinking about 800 million barrels in place.” Crescent Point has delineated the play and is using enhanced horizontal fracture stimulation techniques to get more oil out of the rock and increase its area of productivity. This year, the company plans capital expenditures of approximately $450 million in the play, in line with capital investments over the past three or four years, although spending was as high as $600 million in 2010. “We’re booking over 200 million barrels of proven plus probable reserves, our working interest of the pool,” Smith said. Of the total, Crescent Point has added 175 million barrels of new reserves since buying those interests, thanks largely to more drilling, infi ll drilling and improved technologies. “So that’s pretty significant.” OIL & GAS INQUIRER • JUNE 2013

Saskatchewan

As the formation has matured, Smith said, Crescent Point has bought out a lot of smaller companies. While some larger companies such as PetroBakken, along with a few smaller companies, are still in the formation, consolidations in the area have resulted in fewer larger companies. Rawson said future economics in the Saskatchewan Bakken would reflect the growth of secondary recovery methods in the formation, something companies are already starting to explore. “There’s a lot of work on waterflood pilots going on right now in Viewfield, led by Crescent Point,” he said. “Separately,

PetroBakken is testing gas injection as an alternative way to flood it and increase recoveries. Those developments are being very closely watched.” Smith said Crescent Point is working with the Saskatchewan government on unitization of four separate units side-by-side, which he is optimistic will occur in 2013. “Once we’re unitized we can implement a waterflood.” According to Smith, at eight wells per section, the company’s current Bakken recovery is about 19 per cent, primary. However, waterf looding will increase recovery to over 30 per cent.

“In the near term, you’re probably going to see 1.5 [billion] to two billion barrels under flood in the core area; it’s in that order of magnitude and we have a ways to go.” To date, Crescent Point has converted 45–46 wells to injection, and the company is looking to convert another 20 in 2013. Smith said Bakken play is tight rock, which traditionally has not been considered economically floodable, but Crescent Point pioneered using fractured horizontal oil wells as the injectors. “We’ve proved that it works, we’ve proved that it’s repeatable economically across the play, and now with unitization, we’re planning to go commercial across the field.”

Tundra, Enbridge growing rail transportation Tundra Energy Marketing Limited has entered into a memorandum of understanding with Enbridge Inc. to jointly own and expand the previously announced Tundra crude oil rail-loading terminal near Cromer, Man. The terminal is designed to improve market access for light oil producers in Manitoba, Saskatchewan and North Dakota. Tundra and Enbridge will each own 50 per cent of the joint venture. They will build a terminal capable of loading up to 60,000 barrels per day into railcars interconnecting to Enbridge’s Bakken Pipeline expansion project, Enbridge Pipelines (Sa sk atc hewa n) I nc . a nd Tu nd r a’s Manitoba gathering systems to move Midale, Light Sour Blend and North Dakota Bakken oil through the facility. In addition, the facility will have access to trucked-in volumes and tank storage capabilities. Tundra will build and operate the facility and CN Rail will provide the rail service.

60,000 barrels per day

Rail capacity of new Tundra terminal by 2014

“This project continues Tundra’s commitment to providing infrastructure for producers in Manitoba and Saskatchewan to enhance their options for marketing and storing their production,” Bryan Lankester,

president of Tundra Energy Marketing, said in a news release. The project will be completed in two phases. The first phase will be a loading facility with the ability to load 30,000 barrels per day from trucks and Tundra’s existing pipeline network. The phase is already under construction and is expected to be in service by July 1, 2013. The second phase, which will include connectivity to Enbridge’s pipeline systems, will bring capacity up to 60,000 barrels per day by the fi rst quarter of 2014. Tundra Energy Marketing handles crude oil on behalf of producers in the Williston Basin, including its parent company, Tundra Oil & Gas Partnership, which has been an active driller in the area for the past 32 years. Tundra Oil & Gas is a wholly owned business of Winnipeg-based James Richardson & Sons, Limited, a privately owned, family company established in 1857.

Saskatchewan brings in $7.7 million at April land sale The April sale of petroleum and natural gas rights in Saskatchewan brought in $7.7 million in revenue for the province. A total of 8,353 hectares exchanged hands at an average of $922.29. Year-to-date, the province has collected $19.61 million on 34,880 hectares at an average price of 62

JUNE 2013 • OIL & GAS INQUIRER

$562.21 per hectare. To the same point last year, $45.16 million had come into Saskatchewan coffers on 80,229 hectares at an average of $562.84. “While land sale activity has been comparatively quiet over the past year, if you consider the all-time record set back

in 2008, it is to be expected as industry concentrates on drilling the huge inventory of land that has been acquired,” said Energ y and Resources Minister Tim McMillan. “There are a significant number of leases up for renewal in the next few years, and we expect that much

Saskatchewan

of that land will revert back to the Crown and, as a result, there could be increased land sale revenue.” There were 14 parcels that received “no acceptable bids” at the land sale. Paul Mahnic, director of the petroleum tenure branch with the Saskatchewan government, said the province does not have a minimum bid requirement. “In the April sale, the 14 bids that were rejected were well below what has been determined to be the fair market value of the Crown rights, given [the] present and longer-term outlook for commodity prices, geological potential of the area, and comparative prices received for rights in similar areas,” he said. “The ministry’s mandate includes ensuring the province receives fair value for its non-renewable resources. In other words, we won’t give them away at a price that is deemed unacceptable.” In addition, 21 parcels at the sale received no bids. “In Saskatchewan, we do not penalize companies that request lands for posting who subsequently do not submit bids on

any or all of the lands they’d requested,” he added. “However, the minister does have the regulatory discretion to reject posting requests, or reconfigure them, which may occur if it is determined that it is in the best interests of the province to do so.” At this month’s sale, the WeyburnEstevan area received the most bids with sales of $5 million. The Lloydminster area was next at $1.1 million, followed by the Swift Current area at $1 million, while the Kindersley-Kerrobert area received $623,103. “Industry continues to pay a premium for the lands it acquires, with this sale averaging more than $900 per hectare,” McMillan added. “Drilling activity is steady, and with major investments by industry in secondary recovery projects that have the potential to increase production from the Bakken, the future looks bright for Saskatchewan’s oilpatch.” The top purchaser of acreage in the province was Federated Co-operatives Limited, which spent $3.82 million to acquire one lease parcel and one exploration licence.

It will take an increasing amount of natural gas to keep Saskatchewan’s economy fired up.

We’re ready.

The top price paid for a single lease wa s $826,252 , successf u l ly subm itted by Scott Land & Lease Ltd. for a 32.37-hectare parcel situated within the Clintonville Shaunavon Oil Pool, seven kilometres west of the town of Shaunavon. This parcel generated the land sale perhectare high of $25,525.25. The parcel included legal subdivisions 13 and 14 of section 21 at 08-19W3. The licence bonus high of $3.14 million was paid by Federated Co-operatives for an 807.05-hectare block located partially within the Viewfield Bakken Sand Oil Pool, three kilometres southwest of Corning. The parcel, which attracted a per-hectare price of $3,886.89, included legal subdivisions seven and eight of section six at 11-07W2. Gas prone areas of the prov ince attracted bonus bids of $34,403.30 for 259.09 hectares, an average of $132.79. Parcels offering deeper rights only brought in $1.72 million (22.28 per cent of the sale) for an average price of $591.81. — DAILY OIL BULLETIN

Saskatchewan continues to experience rapid economic growth year after year. Potash mines are multiplying across the Province, construction cranes are rising above our cities, and power plants are increasing their capacities. Each mine, industrial site, refinery, or office building needs a dependable supply of natural gas to power its expansion and future operation. TransGas is strategically positioned to provide safe and reliable natural gas transportation and storage services to support this unprecedented growth in Saskatchewan.

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Saskatchewan

Novus builds its Viking reserve base A successful 2012 drilling program allowed Novus Energy Inc. to substantially increase its year-end 2012 reserves and average daily production. The company’s year-end independent reserve evaluation, prepared by Sproule Associates Limited, shows that gross proved reserves at Dec. 31, 2012, increased by 68 per cent to 14.85 million barrels equivalent, up substantially from 8.84 million barrels at year-end 2011. Proved plus probable (2P) reserves at Dec. 31, 2012, increased by 56 per cent to 22.72 million barrels, up from 14.56 million barrels one year earlier. Oil and natural gas liquids (NGLs) at Dec. 31, 2012, represent 82 per cent of 2P reserves on a barrels equivalent basis and 81 per cent of total proved reserves. The company’s reserve replacement for the year was 829 per cent on a proved and

probable basis and 637 per cent based on proved reserves. Operationally, the company’s average production for 2012 was 3,059 barrels equivalent per day, representing 55 per cent yearover-year average production volume growth. Novus achieved production of 3,444 barrels equivalent per day in the fourth quarter of 2012 (78 per cent oil and NGLs) representing a 21 per cent increase over fourth quarter 2011 production volumes. The preliminary estimate of fi rst quarter 2013 average production based on field estimates is 4,090 barrels per day. The company noted that the operating netbacks in 2012 for its Viking light oil production in Dodsland were estimated to be $54.16 per barrel. During 2012, Novus operated the drilling of 72 wells at Dodsland all using horizontal multistage fracturing technology.

During the fourth quarter of 2012, Novus drilled, completed and placed on production three wells to the west of its Flaxcombe field. The westernmost well drilled in this extension is situated over 12 miles from the Flaxcombe field. In the first quarter of 2013, Novus drilled, cased and put on production four additional successful wells in the region. With recent land purchases, Novus controls approximately 17.5 sections of land in this western extension and with its success, has materially added to its drilling inventory. During the first quarter of 2013, the company drilled a total of 17 wells all using horizontal multistage fracturing technology. Twenty wells were completed and brought on production during the quarter. Novus currently controls 219 net sections of Viking rights, and has a risked drilling inventory of 1,585 net, undrilled Viking oil locations.

Renegade increases first quarter production Renegade Petroleum Ltd. r e p or te d increased production on its Saskatchewan oil properties during an update in April. Renegade expects its average production during the fi rst quarter of 2013 to be about 7,800–7,850 barrels equivalent per day (95 per cent light oil), and the company expects to exit the quarter at about 7,900 barrels per day as assets in the Viking and all focus areas of southeastern Saskatchewan continue to perform at or above expectations. If average production ends for the quarter as the company expects, it would be about a 115 per cent increase from the 3,644 barrels per day the company reported for the first quarter in 2012. However, the company also reported it experienced reservoir performance issues in its Redvers area during the quarter, due to an earlier-than-anticipated water cut influx. As a result, production from the area is lower by approximately 300 barrels per day per day in the first quarter. Renegade is evaluating various work techniques in an attempt to regain lost production and the company is encouraged by initial operations. 64

JUNE 2013 • OIL & GAS INQUIRER

For 2013, the company approved a capital budget of $79.6 million, with $51.4 million earmarked for southeastern Saskatchewan and $28.2 million for westcentral Saskatchewan.

Average well costs in the first quarter were about $950,000 per well, which is in line with Renegade Petroleum Ltd.’s budget.

During the first quarter of 2013, Renegade brought on stream 22 (22 net) Viking wells in west-central Saskatchewan with a 100 per cent success rate. Of the 22 net wells drilled, the average initial production (IP30) rate of 17 (17 net) wells

was 55 barrels per day, which exceeded the company’s type curve by 12 per cent. Additionally, Renegade has five (five net) wells scheduled to have optimization operations post spring breakup. Average well costs in the fi rst quarter were about $950,000 per well, which is in line with the company’s budget. Renegade also drilled four (two net) wells in southeastern Saskatchewan in the fi rst quarter with a 75 per cent success rate. Of those wells drilled, one (0.5 net) well had an IP30 rate of 130 barrels per day and is currently producing 135 barrels per day after 46 days. Two (one net) of the wells are awaiting further stimulation post-breakup, while the company expects to abandon one (0.5 net) well. Of 200 identified locations on a large inventory of assets the company acquired in late 2012, Renegade completed full technical evaluations on over 90 locations in the first quarter of 2013 and is well positioned to begin its drilling program coming out of breakup with a stable inventory of low-risk locations. — DAILY OIL BULLETIN

Saskatchewan

Husky reports higher heavy oil production By Pat Roche

Husky Energy Inc. reported marginally higher production but lower earnings in the first quarter. Total production from heavy oil and thermal projects over the quarter was about 122,000 barrels per day compared to 106,000 barrels per day in the first quarter of 2012. Total thermal developments, including Tucker, produced about 48,000 barrels per day, up from 30,000 barrels per day one year earlier. Combined average volumes of 18,000 barrels per day were maintained at the Pikes Peak South and Paradise Hill thermal projects, ahead of their 11,500-barrel-per-day total design rates. Construction on the 3,500-barrel-per-day Sandall thermal development is now 55 per cent complete, with initial drilling underway and first production planned for 2014. Initial site work continued at the 10,000-barrel-per-day commercial thermal project at Rush Lake, which remains on track for first oil in 2015. The first single well pair pilot continues to produce, and progress is being made toward start-up of a second well pair, scheduled for the second quarter of 2013. Thirty-eight horizontal heavy oil wells were drilled in the first quarter out of a planned 140-well program for 2013, along with 55 cold heav y oil production with sand wells out of a planned 200-well program. Reviewing its oil resource plays, Husky said 45 horizontal wells (gross) were drilled in the Bakken, Lower Shaunavon, Viking, Cardium and at Rainbow Muskwa in the first quarter. Two ver tical wells drilled in 2012 at t he Slater R iver Canol play in the Northwest Territories were completed and tested during the first quarter. Results are being evaluated and community consultations are underway for a proposed 2013-14 program. About half of a 40-kilometre all-season access road was built during the 2012-13 winter program, with operations scheduled to resume in the third quarter. On the gas side, 10 liquids-rich wells were drilled at the Ansell gas play, with 12 gas wells completed by March 31. Production at Ansell reached more than 14,000 barrels equivalent per day in the first quarter. In the oilsands, the first phase of the Sunrise steam assisted gravity drainage project is advancing toward first production in 2014 and is about two-thirds complete. The central processing facility is progressing with all critical equipment and modules in place for the first of two processing plants. Field facilities are being finalized with all well pads and pipelines scheduled for completion later this year. E a rly e ng i nee r i ng work on t he ne x t ph a se of t he 200,000-barrel-per-day (100,000-barrel-per-day net to Husky) development is continuing. A regulatory application for a 3,000-barrel-per-day bitumen carbonate pilot at Saleski has been filed.

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JUNE 2013 • OIL & GAS INQUIRER

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acing slower growth at home due to a stubborn oversupply of natural gas and bottlenecks in exporting expanding oil production, Canada’s service and supply companies are expanding internationally. But the traditional market for expansion, the United States, is facing similar challenges, meaning companies are having to look further afield for growth opportunities. Precision Drilling Ltd. president and chief executive officer Kevin Neveu says the slowdown in both Canadian and American markets that began in late 2012 has continued into 2013. Neveu, however remains hopeful it is a short-term trend. “While customer spending has been restrained during the first quarter, continued strength in commodity prices should lead to improving activity as the year continues,” he says. “We believe in the long-term positive fundamentals of the North American unconventional oil and gas market.” In Canada, Precision’s average active rig count in the fi rst quarter of 2013 was 123 rigs, down 11 from last year’s fi rst quarter, and up 34 rigs from last year’s fourth quarter. Management expects seasonal softness in the second quarter in Canada, but the third is expected to benefit from past fleet enhancements, the company says. In the United States, Precision’s average active rig count in the quarter was 81 rigs, down 22 from last year’s fi rst quarter and down six rigs from the year’s fourth quarter. On April 19, 2013, the U.S. active land drilling rig count was down about 11 per cent from the same time last year, Precision says. The company has 79 rigs active in the United States and expects its rig count there to be relatively unchanged in the coming months. “The plummet in gas-directed drilling that began in the U.S. in late 2011, continuing through the first quarter of this year, has put pressure on industry utilization and day rates,” Neveu says. “Precision’s drilling activity was down 23 per cent in the quarter, while day rates remained stable, reflecting the higher percentage of Super Series rigs active in the quarter.”

The trend to oil-directed drilling in North America continued in 2013. During the quarter, about 74 per cent of the Canadian industry’s active rigs and 76 per cent of the U.S. industry’s active rigs were drilling for oil, compared to 72 per cent and 64 per cent, respectively, during last year’s period. Precision’s completion and production services division also saw challenges in Canada, with industry well servicing and completions ramping up slower than drilling in the quarter, Neveu adds. Offsetting the decline in Canadian activity, the company’s U.S. completions and production group generated activity almost six times that seen in last year’s first quarter, he says. While activity in North America has stalled, internationally Precision continues expansion. “Precision’s contract for two rigs for deployment to Northern Iraq in the Kurdistan Region is the most recent step in our international expansion. These rigs will be mobilized from our U.S. fleet and will operate for an international oil company on long-term contracts. Including the two new builds announced in December for Kuwait, by mid-2014 we expect to have seven rigs operating in the Arabian Gulf region and believe additional opportunities for Precision’s high performance, high-value services will emerge,” he says. Precision also continues growing in Mexico. “The additions to our Mexican fleet include one rig to be deployed late in the fi rst quarter and a second rig in the second quarter moving our Mexican fleet to seven rigs, with six currently contracted to drill deep, high pressure oil wells for international integrated project service providers,” says Neveu. Canada’s second-largest drilling contractor, Ensign Energy Services Inc., is also growing internationally. In 2012, Ensign’s international operations reported revenues of $78 million, a 27 percent increase from revenue of $376.5 million in 2011. International revenue totaled $139.7 million in the fourth quarter of 2012, a 20 percent increase from $116.0 million recorded in the corresponding period of the prior year. The company’s international operations recorded 11,612 operating days in 2012, an

OIL & GAS INQUIRER • JUNE 2013

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eight percent increase from 10,748 operating days recorded in 2011. International operating days for the three months ended Dec. 31, 2012, increased 12 percent over the comparable prior year period to 3,010 operating days, compared to 2,698 operating days in the fourth quarter of 2011. Ensign credits the growth to stronger demand for oilfield services in Latin America and throughout the eastern hemisphere. It says fewer political and weather disruptions also impacted the numbers. “In 2011, international operating results were weakened due to the disruption of operations arising from challenges outside of the company’s control, including severe flooding in Australia and political unrest in parts of the Middle East and North Africa,” it reports. “The company resumed its operations in Libya late in 2012 with the start-up of one drilling rig and a second drilling rig is expected to start up in the first half of 2013.” Ensign continues taking advantage of the natural gas boom in Australia. It added two new automated drilling rigs to its Australian equipment fleet in 2012. In addition, one drilling rig was transferred to Australia from its Canadian drilling rig fleet. Another drilling rig was transferred to Latin America from Ensign’s U.S. drilling rig fleet during the year. It also decommissioned or disposed of three inactive drilling rigs from its international operations during the year, and six drilling rigs were transferred from Mexico to the U.S. operations. Savanna Energy Services Corp. saw its efforts to establish a foothold in the Australian natural gas market take off in 2012. Revenue from Savanna’s Australian operations was $22.7 million in the fourth quarter of 2012, up $14.1 million or 165 per cent from the previous year and up 14 per cent over the previous quarter. Australian activity levels were up year over year due to delivery of drilling and workover equipment to market by Savanna, as well as Savanna’s customers increasing their work scope substantially. “Australian drilling activity demonstrated the most significant spike, although workover activity continued to increase as well,” says the company. Savanna exited the quarter with four drilling and four workover rigs operating in Australia, along with expanded trucking and rental operations.

COMPLETIONS EXPERTS WORK TO EXPAND INTERNATIONAL OUTPOST Canadian completions specialists have been in big time expansion mode the last few years as the multistage fracturing revolution has spread from tight gas plays into oilfields across Canada and the United States. Canadian companies

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gained a major position in American markets, but that growth came to an end in late 2012, Calfrac Well Services Ltd. chief executive officer and director Doug Ramsay reported to shareholders late this winter. “The latter part of the fourth quarter brought particularly low equipment utilization for the industry as the United States rig count declined steadily in the company’s operating regions as the quarter progressed,” Ramsay notes. “The sharp decline in natural gas-oriented drilling and completion activity, combined with the significant increase in fracturing capacity in the United States, resulted in an increasingly predatory pricing environment in the fourth quarter in which the company chose not to participate. In response to these market conditions, Calfrac instituted numerous cost reduction measures through the fourth quarter and early in the first quarter of 2013 to maintain profitability in this lowerrevenue environment.” With the North American market saturated, pressure pumpers are now focused on international growth. Ramsay says cold weather and a slowing market impacted the company’s Russian operations last year. But this year things are set to improve. “The company completed a number of multistage fracturing jobs in horizontal wells during the fourth quarter, with additional horizontal pressure pumping work performed in January, and anticipates this trend to accelerate in 2013,” he explains. Multistage fracturing operations are also gaining a toehold in Latin America, he adds. “The company passed a milestone in the development of its Mexican business, completing its fi rst two multistage fracturing treatments in horizontal wells during the fourth quarter,” he explains. “Both wells were 16-stage completions that were supported by equipment from our United States operations and incorporated many of the technologies that Calfrac provides in Canada and the United States. These technologies are now being deployed to improve Mexican production rates, and Calfrac is very pleased with this emerging trend and the initial successes that have been realized. The company is optimistic that these technologies will provide a solid basis for growth in the Mexican market.” Argentina is also looking like an area for future expansion, Ramsay says. During the fourth quarter, the company deployed additional fracturing equipment into Argentina and planned to commence operations to service conventional and emerging unconventional shale natural gas and tight oil plays in Argentina. Calfrac also expanded its presence in Colombia through the deployment of additional cementing equipment, and currently operates six crews. It was successful in a recent long-term cementing services

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F O E C N E G “THE EMER L COMPLETIONS HORIZONTA AGE FRACTURING T S I T L U E M V I T I AND S O P EA B O T S E U CONTIN T IN RUSSIA.” N E M P O L E DEV — Dale

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JUNE 2013 • OIL & GAS INQUIRER

er Well S Trican , r e c ffi

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contract tender with one of the largest oil and gas producers in that country. This development is anticipated to be a growth driver for Calfrac’s Colombian operations and it is expected that this emerging international market will grow. Calgary-based Trican Well Service Ltd. also sees growth in its international operations in Russia, Kazakhstan, Algeria, Australia, Saudi Arabia and Colombia. In Russia, “Our fracturing activity was particularly strong as job count increased slightly and fracturing job size increased substantially year over year due to an increase in work performed on horizontal wells, Trican chief executive officer Dale Dusterhoft reported to shareholders in his year-end address. “The emergence of horizontal completions and multistage fracturing continues to be a positive development in Russia. Approximately 12 per cent of our 2012 fourth-quarter Russian fracturing revenue was from work performed on horizontal wells, compared to approximately three per cent in the fourth quarter of 2011. This is an important development for the pressure pumping industry in Russia, as the shift towards more unconventional drilling and completions is expected to increase the demand for horsepower in the region and place a larger emphasis on technology.” “Fourth-quarter operating results were strong in Kazakhstan for our two fracturing crews operating in the region,” Dusterhoft added. “We continue to see improved results for our Algerian operations as year-over-year margins improved substantially. We are also continuing to grow and establish our cementing business in Australia and had solid revenue growth for our cementing service line during the fourth quarter of 2012.”

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JUNE 2013 • OIL & GAS INQUIRER

— Hal Kvisle, president and chief executive officer, Talisman Energy Inc.

for the Hamaca oil field discovery in the block. At present, it is pre-constructing production facilities to be ready for when the blanket environmental licence for the block is granted. In block CPO-1, the company finished drilling the Altillo Oeste-1 exploration well in January. The well was plugged and abandoned as a dry hole. In block CPO-12, Pacific Rubiales finished drilling the Hayuelo-1x well, which was also plugged and abandoned as a dry hole. In late March, the company was awarded the environmental permits for the Quifa Hydrocarbon Exploitation Area, which covers most of the Quifa block and will allow for continued production growth at Quifa SW as well as for the restarting of the drilling campaign in the exploration area surrounding the Rubiales field. It also received bids for the acquisition of 721 square kilometres of 3-D seismic in the northwestern portion of the block. In the Lower Magdalena Basin, the Manamo-1x and Capure-1x exploration wells have resulted in two significant gas condensate discoveries in the company’s 100 per cent working interest Guama block. These two wells confirmed and extended the gas condensate field that was

booked with certified proved plus probable reserves at year-end 2012. The Manamo-1x well flow tested at a maximum rate of 4.9 million barrels a day with 296 barrels per day of 54 °API condensate. The Capure-1x well is currently drilling and has encountered 23 feet of gas or gas condensate pay indicated on petrophysical logs in clean sands of the Porquero A formation, a secondary exploration target of the well. The well is now drilling through the primary target Porquero C and D intervals at a depth of 4,150 feet measured depth, with total depth estimated at 7,400 feet measured depth. In the Santos Basin offshore Brazil, the Kangaroo-1 and Emu-1 exploration wells were drilled to a total depth of 10,004 feet and 14,370 feet measured depth, respectively. The Kangaroo-1 well discovered a 25-metre (82-foot) gross hydrocarbon-bearing section in the Eocene. Wireline logs, pressure data and fluid sample analysis confirmed the presence of 42 °API oil in two separate intervals. The company and its partner, Karoon Gas Australia Ltd., are proceeding with plans to drill an appraisal well to further delineate the extent of the Kangaroo Eocene oil discovery. In the onshore Ucayali-Maranon basins in Peru, the Yahuish-1x well on block 138

Photo: iStockphoto.com/ HHakim

to be a quarterly record in the range of 126,000 barrels of oil equivalent per day to 128,000 barrels per day, an increase of 30 per cent from the 2012 average, Ronald Pantin, chief executive officer says. Exploration activity so far this year includes 10 wells, with one currently drilling, resulting in four significant oil discoveries, including an oil discovery in its first well drilled offshore Brazil, and two natural gas/condensate discoveries, for a 67 per cent success rate. In the Llanos Basin in Colombia, two wells drilled in the Cubiro block, and one well drilled in the Arrendajo block, have resulted in new light oil discoveries. The Copa D-1x encountered 28 feet of net pay and tested over 800 barrels per day of 38 °API oil from a single completed zone. The Copa A Norte-1x well encountered 25 feet of net pay and is currently being completed. The Yaguazo-1x well reached total depth at 6,700 feet measured depth having encountered 15 feet of net, and the company is preparing to complete and test the sand. Also in the Llanos Basin, southwest of the company’s Rubiales and Quifa fields, Pacific Rubiales completed the acquisition this month of 366 square kilometres of 3-D seismic in the northern part of Block CPE-6. This seismic data, along with the 16 wells that have been drilled into the reservoir, will be used to detail the stratigraphic and structural models needed to construct the development plan

“ We are unlocking what could be a giant oilfield [in Iraq], which we could develop ourselves or through some sort of joint venture or partnership. Delineation drilling will continue throughout 2013.”

is underway. In block 135, the company has completed 25 per cent of a 789-kilometre 2-D seismic acquisition program. The field processing of this seismic indicates the presence of large structures involving Cretaceous and Pre-Cretaceous units. In block Z-1 in the offshore Tumbes Basin, the company has finished the acquisition of 429 square kilometres of 3-D seismic data. The data is currently being merged and processed together with the 1,143-squarekilometre 3-D seismic survey previously acquired by BPZ Energy, operator of the block. The preliminary field processing of this 3-D seismic data looks promising, said Pacific Rubiales. Calgary-based Gran Tierra Energy Inc. is also focused on South America, with a 2013 capital program of $363 million for its exploration and production development operations in Colombia, Brazil, Peru and Argentina. The capital spending program allocates $202 million for drilling, $65 million for facilities, equipment and pipelines, $93 million for seismic activities and $3 million associated with corporate activities. Approximately 50 per cent of the drilling budget is for development and appraisal drilling and approximately 50 per cent is for exploration drilling. The budget currently contemplates the drilling of 10 wells in Colombia, six wells in Argentina, two wells in Brazil and one well in Peru. The capital spending program also includes funds for 1,148 kilometres of 2-D and 308 square kilometres of 3-D seismic acquisition programs in Colombia, Peru, Argentina and Brazil, primarily in preparation for additional exploration and production drilling operations in 2013 and beyond. Excluding potential exploration success, Gran Tierra Energy is expecting 2013 production to average 27,000 barrels of oil equivalent per day gross working interest with no pipeline disruptions. Production is expected to average approximately 20,000 barrels per day net. Approximately 96 per cent of this production consists of light oil, with the balance consisting of natural gas. “Gran Tierra Energy will continue executing its current strategy through 2013, a strategy that has consistently grown land, reserves and production year over year for the last seven years,” Dana Coffield, president and chief executive officer, said. “For the first time, we will have active drilling and development activities in all four countries of operations,” he said. “Our focus on execution sees us entering

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2013 with a robust drilling portfolio with a balanced mix of development drilling to maintain our base of reserves and production, and appraisal and exploration drilling to grow that base.” Petrominerales Ltd. plans to drill up to 35 wells with a balance of high-impact exploration and development drilling opportunities in Colombia, Peru and Brazil. It’s newly acquired Brazilian assets provide a large, unconventional resource, with undiscovered petroleum initially in place of more than one billion barrels and more than 100 potential development locations, said the company. Production is 60 barrels of oil equivalent per day with associated proved plus probable reserves of more than 400,000 barrels. In addition, the assets offer an attractive fiscal regime, close proximity to existing infrastructure and are complementary to Petrominerales’ existing high impact exploration portfolio, it said. The Recôncavo Basin is a 10,200square-kilometre on- and offshore basin, located 85 kilometres north of the city of Salvador in northeastern Brazil. Brazil’s first oil production came from this basin in 1939. Since then, over 6,000 wells have been drilled in the basin, with cumulative production exceeding 1.5 billion barrels of light oil from 86 fields. Current production is over 60,000 barrels per day, and the majority of the basin’s production comes from the Sergi, Agua Grande and Candeias reservoirs found at depths of 315–1,975 metres in this area. Petrominerales said its primary target is the Gomo member of the Candeias formation, which is both the mature source rock and contains the prospective reservoir sands. The Gomo contains the main source rock for the Recôncavo Basin as well as the main reservoir units. On the company’s blocks, the Gomo is oil saturated and found at depths between 2,500 and 3,200 metres. There have been 24 wells drilled by other operators that have identified thick, stacked, oil-bearing sands. The Gomo net pay on these blocks ranges between 10 and 200 metres. Based on existing seismic data and well control, Petrominerales initially estimates a portion of the lands to contain more than one billion barrels of undiscovered petroleum initially in place in the Gomo. The estimate is based on a porosity cut-off of 10 per cent, average net pay thickness of 48 metres and a water saturation of 25 per cent. On this portion of the acreage

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and with success, the company estimates a vertical well inventory of between 100 and 200 locations with the opportunity to optimize development using horizontal wells. The initial focus will be to demonstrate the commercial deliverability of the Gomo sands using multistage fracture stimulation technologies, said Petrominerales. In 2013, it expects to drill at least two wells and be in a position to execute a larger-scale development program starting in 2014. The reserves are currently only assigned to the Caruacu formation. Petrominerales said it has identified up to three additional locations in the Gomo Member and two Caruacu development locations defined by seismic. It also sees additional potential in the Sergi and Agua Grande zones. The company said its vision is to implement a large-scale, repeatable, low-risk, multi-well development program in Brazil starting as early as 2014. The 2013 capital program consists of drilling up to 12 exploration wells in Llanos Basin of Colombia targeting light oil resources of up to 120 million barrels of undiscovered petroleum initially in place. As part of its 2013 capital program, Petrominerales also plans to acquire 436 square kilometres of new, high-quality 3-D seismic on its Block 25, Mapache and Las Aguilas blocks in the Deep Llanos basin in Colombia and will have exposure to up to two high-impact exploration prospects to be drilled by its joint-venture partner in Peru. Petrominerales also provided a production update. Output averaged 25,032 barrels of oil per day during November, three per cent lower than the October, primarily due to production additions coming on late in the month offset by natural declines.

Talisman Energy is also active in the Middle East in the Kurdistan area of Iraq where it has drilled three successful exploration wells. Two of the wells are gas wells with strong condensate production. The third is a light oil well that may have tapped a billion barrel reservoir. “We are unlocking what could be a giant oilfield, which we could develop ourselves or through some sort of joint venture or partnership. Delineation drilling will continue throughout 2013,” Kvisle noted. In Egypt, TransGlobe Energy Corporation continues to successfully OIL & GAS INQUIRER • JUNE 2013

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find oil and gas despite the political strife facing the country. TranGlobe plans on spending $124 million in Egypt in 2013, with $54 million (42 per cent) to be spent on exploration with 23 (19.9 net) wells and seismic and $75 million (58 per cent) on development with 28 (25.3 net) wells and facilities. Forecast production of 22,500 barrels of oil per day represents a 29 per cent increase over the 2012-estimated production of 17,400 barrels of oil per day. Meanwhile, in equally strife-torn Syria, Suncor Energy Inc. completed negotiations with the National Oil Company in Libya in the first quarter regarding its exploration commitments under its exploration and production sharing agreements. As a result, the company has received an extension to reflect the time that Suncor was in force majeure due to political unrest and was unable to fulfill its exploration commitments. The 2013

exploration drilling program is currently underway and the company has resumed drilling at one exploration well during the first quarter of 2013. Current production is around 45,000 barrels per day.

Bankers Petroleum Ltd. is one of the more unique Canadian producers working overseas, with its major core area in Albania. The company recently reported that production from the Patos-Marinza oilfield in Albania for the first quarter of 2013 was 16,916 barrels of oil per day, 4.7 per cent higher than 16,163 barrels of oil per day in the fourth quarter of 2012. The company reported that 32 horizontal wells were drilled during the first quarter—31 horizontal production wells and one horizontal lateral redrill well in the main area of the Patos-Marinza field. Twenty-eight of these wells were

completed and are on production and four will be placed on production this month. Bankers continues to focus horizontal drilling in the primary Driza reservoir zones and has expanded drilling in several Marinza zones with encouraging results. Pattern development drilling for secondary recovery techniques in the Marinza and Lower Driza zones was started in the first quarter. The drilling rig damaged in January has now been repaired and the company has five drilling rigs in operation. The company began preliminary injectivity testing at the first pilot polymer flood location. Following the test completion, expected in the second quarter, progression of the pilot will be sanctioned should results merit further pilot work at this location. The second exploration drilling location in Block F is scheduled to be drilled in the second quarter of 2013. Lease access has been obtained and site construction will start shortly.

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life. And, together with the Evergreen Centre for Research & Innovation, Alberta Environment, and Alberta Sustainable Resource Development, Risley is providing next generation resource solutions through a collaborative approach with contractors, communities and government, where only the “best is acceptable”—a vision and a mission that encourage everyone to Step Ahead!® For more information, please contact: Risley Equipment Inc. Innovative Resource Solutions www.GoRisley.com Dean.Isley@GoRisley.com Cell: 780-228-2464 Corporate: 780-532-3282 Toll-Free: 866-783-7243 Risley: Step Ahead!®

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Feature

D Arab nations invite Alberta firms to Middle East By James Mahony

iplomats from Middle Eastern nations met in Calgary in April, calling for a greater Canadian presence in their countries’ oil and gas sectors. Having toured Fort McMurray and the oilsands earlier, the Council of Arab League Ambassadors to Canada was also in Calgary to meet industry executives and wind up a busy tour of the province. Representing seven Middle Eastern countries, the visitors expressed interest in Canadian oil and gas technology and expertise, inviting this country’s producers and technology firms to visit the Middle East for a tour of their own. During presentations, diplomats from Algeria, Egypt, Iraq, Lebanon, Morocco, Tunisia, the United Arab Emirates (UAE) and the Palestinian people spoke briefly, thanking their hosts, including Cal Dallas, Alberta’s international and intergovernmental relations minister, for the grand tour. Among those speaking was Egyptian Ambassador Wael Amoulmagd, who touched on Egypt’s political situation, given the attention the country’s recent revolution has attracted around the world.

“It’s a hopeful moment in Egypt,” he told a small audience. “We’ve achieved so much in two years. We’ve moved forward peacefully and are making significant movement in electing a civilian president, changing our constitution, and establishing the rule of law and government accountability.” “There’s a new social contract between the Egyptian people and those who govern them,” he said. “Gone are the days of absolute power and non-accountability. We’re very hopeful. You’re still going to hear we’re not moving forward as fast as we’d like, but it’s a nation of 90 million people, and you’re not going to change it overnight. It will take time.” Before the revolution, Egypt’s economic growth was running at six to seven per cent annually, although the benefits were unevenly shared, due to corruption and a lack of transparency under the old regime, Amoulmagd said. Today, thanks to a more level playing field, the country has a better climate for investment, both domestic and foreign. OIL & GAS INQUIRER • JUNE 2013

Feature

“When someone asks me about investment in Iraq, I can say the sky is the limit.”

He described the country’s investment potential as “tremendous,” especially in the field of energy development. “We have a very well-developed oil and gas industry and consume much of what we produce, but still export significant amounts,” he said, noting Egypt could also use Canadian expertise in the realm of environmental control and water treatment, among others. Morocco was also represented at Friday’s event. Unlike Egypt, the North African country is a net oil and gas importer, which puts a burden on the country’s international balance of payments. As a result, the government is keen to see western oil and gas producers begin to explore its territory—both on- and offshore, Ambassador Nouzha Chekrouni told the group. Chekrouni said her country shows potential in oil and shales, and its government is also looking for opportunities to

JUNE 2013 • OIL & GAS INQUIRER

work with foreign companies, including Canadian ones, with a view to developing that potential. Although the diplomats were in Calgary to meet executives from Canada’s oil industry, among others, relatively few producers were present for the morning presentations, organized by Calgary Economic Development, although more turned out for the luncheon meeting that followed. For Calgary executives who attended Friday’s event, some Arab nations drew more attention than others, including the UAE, with its thriving oil and gas sector. For his part, UAE Ambassador Mohammed Saif Helal Al Shehhi estimated his country has invested some $30 billion in Canada, much of it in two companies: TAQA (Abu Dhabi National Energy Company PJSC) and Nova Chemical Corporation. All told, he said roughly 150 Canadian companies currently do business in the

UAE, which chalked up about $1.5 billion in bilateral trade with Canada last year. Some 40,000 Canadian citizens currently make their home in the UAE, and Al Shehhi said the country still holds “vast opportunities” to do business and invest in its oil and gas sector. In terms of risk profile, the countries represented at Friday’s event covered a broad spectrum. Iraq was represented by its ambassador, Abdulrahman al-Hussaini, who noted that relatively few Canadians currently work in his country, compared to expatriates from other nations. Yet, he expressed hope that more Canadians would visit and, like some of his colleagues, suggested that someone should lead a Canadian business delegation to the Middle East sometime in the near future, an idea that was met with applause. “When someone asks me about investment in Iraq, I can say the sky is the limit,” he told the group.

Photo: Tomasz Wyszołmirski/Photos.com

— Abdulrahman al-Hussaini, Iraq ambassador

Business

The latest regional business news

Intelligence Industry profits down in 2012 By Daily Oil Bulletin staﬀ

mpairments booked at year-end by operators, due primarily to lower nat-

Canadian Natural reported the largest reduction in cash fl ow (down

ural gas prices, contributed to a significant decline in year-over-year net

$534 million to a total of $6.01 billion in 2012). Other companies report-

income for Canadian producers.

ing larger year-over-year declines in funds flow included Encana (down

And those declines in net income trickled down to the service industry as well.

US$512 million to a total of $3.43 billion) and Husky (off $477 million to a

For the 86 producing companies surveyed as part of the most recent

total of $4.35 billion).

edition of the JuneWarren-Nickle’s Energy Group’s Oil & Gas Statistics

The 86 producers spent a collective $62.92 billion in 2012 compared to

Quarterly, net income declined by $8.12 billion to a total of $9.34 billion for

$60.1 billion in 2010. Companies with the largest year-over-year increase in

2012, off 47 per cent from $17.46 billion in 2011.

spending included: Crescent Point Energy Corp. (up $1.9 billion), Imperial (up

Only 32 of the surveyed companies booked year-over-year increases in their net income.

$1.62 billion), Cenovus Energy Inc. (up $690 million), MEG Energy Corp. (up $635.06 million) and Nexen Inc. (up $549 million).

Imperial Oil Limited recorded the largest year-over-year boost in profits.

Most producers’ capital budgets exceeded cash flow in 2012, with only

The company’s net income climbed $395 million to a total of $3.77 billion in

eight companies spending less than cash flow. Those companies spending

2012, compared to $3.37 billion in 2011. Imperial was followed by two com-

most in excess of funds flow included Crescent Point (total funds flow of

panies that reported net losses in 2012, but even greater losses the prior

$1.59 billion versus capital spending of $3.37 billion) and MEG (funds flow of

year. Paramount Resources Ltd.’s net income rose $170.08 million to a net

$212.51 million versus capital expenditures of $1.62 billion).

loss of $61.91 million in 2012 (up from a loss of $231.99 million the prior year),

The companies that had the greatest surplus of cash flow after capital

while MGM Energy Corp. booked a net loss of $8.07 million (up from a loss of

spending included Suncor, Canadian Oil Sands Limited, Cenovus, ARC

$160.86 million in 2011).

Resources Ltd. and Longview Oil Corp.

Imperial also had the highest net income of the year, followed by Suncor

On a barrels equivalent basis, production for the producers surveyed

Energy Inc. ($2.78 billion), Husky Energy Inc. ($2.02 billion) and Canadian

rose 155,508 barrels per day to a total of 5.11 million barrels per day in 2012,

Natural Resources Limited ($1.89 billion).

from 4.96 million barrels per day in 2011.

Total funds flow for the 86 companies declined slightly to $51.12 bil-

Canadian Natural reported the biggest jump in oil and liquids production

lion in 2012 from $52.47 billion the prior year. Suncor recorded the highest

during 2012, to an average 451,378 barrels per day compared to 389,053 bar-

cash flow at $10.19 billion, followed by Canadian Natural ($6.01 billion) and

rels per day in 2010 (a difference of 62,325 barrels per day).

Imperial ($5.05 billion).

Other companies reporting large increases in year-over-year oil and liquids

Of the 11 companies that reported more than $1 billion in cash flow for the

output included: Cenovus (up 31,164 barrels per day), ConocoPhillips Canada

year, only two were gas weighted: Encana Corporation (93.14 per cent gas

(25,000 barrels per day), Crescent Point (23,100 barrels per day), Suncor

weighted in the fourth quarter) and Talisman Energy Inc. (63.62 per cent gas

(14,720 barrels per day) and Devon Canada Corporation (11,500 barrels

weighted in the fourth quarter).

per day).

OIL & GAS INQUIRER • JUNE 2013

Business Intelligence

Lower profits in the producer community have trickled down to service and supply companies.

Overall, oil and natural gas liquids production rose 238,385 barrels per

The largest year-over-year declines in profit were booked by Trican Well

day, for the companies surveyed, to a total of 2.89 million barrels per day in

Service Ltd. (off $285.30 million), Precision Drilling Corporation (down

2012, from 2.65 million barrels per day in 2011.

$141.12 million) and Calfrac Well Services Ltd. (off $90.31 million).

tion of 493.1 million cubic feet per day to a total of 13.35 billion cubic feet per day in 2012, from 13.85 billion cubic feet per day the prior year.

Twelve-month cash flow for the companies declined $50.64 million to a total of $5.39 billion compared to $5.44 billion in 2011. Those booking the largest year-over-year declines in cash flow were Trican

Service companies reported mixed results in 2012.

(off $377.96 million), Calfrac (off $159.72 million) and Canyon Services Group

Midstream providers enjoyed a highly profitable year, but drillers and

Inc. (down $32.34 million).

pressure pumpers had a more difficult 12 months, as producers cut back on drilling during the second half of the year.

Revenue for the year was stronger, with the 42 companies booking $32.79 billion in 2012, up 13 per cent from $28.96 billion the prior year.

The 42 service and supply and midstream/infrastructure companies

Six companies posted a greater than $100 million year-over-year jump

surveyed had a combined 2012 profit of $2.02 billion, off $357.8 million from

in their revenue: Pembina (up $1.75 billion due in part to its acquisition of

$2.38 billion in 2011.

Provident Energy Ltd. earlier in 2012), Secure (up $478.24 million), Keyera

The largest year-over-year profit increases occurred at Gibson Energy ULC (up $178.79 million), Enerflex Ltd. (up $79.07 million), Pembina Pipeline Corporation ($59.33 million), Inter Pipeline Fund ($59.3 million) and Pulse Seismic Inc. ($22.25 million).

Corp. ($373.12 million), Ensign ($306.95 million), Enerflex ($274.55 million) and AltaGas ($179.7 million). Capital spending for the year totalled $10.82 billion, up 64 per cent or $4.21 billion from $6.61 billion in 2011.

Only 10 other companies booked higher net income in 2012 than in 2011:

Companies with the greatest increase in 2012 spending over 2011

AltaGas Ltd., Logan International Inc., CanElson Drilling Inc., Mullen Group

included: Pembina (up $3.36 billion), AltaGas (up $877.3 million) and Gibson

Ltd., High Arctic Energy Services Inc., Secure Energy Services Inc., Akita

(up $461.4 million).

Drilling Ltd., Ensign Energy Services Inc., TESLA Exploration Ltd. and IROC Energy Services Corp. Inter Pipeline booked the highest net income of the year ($307.2 million), followed by Pembina ($225 million) and Ensign ($217.52 million). Only six companies reported a net loss for the year ended Dec. 31, 2012. The largest net loss in the 12-month period was reported by GASFRAC Energy Services Inc. ($77.47 million). 84

JUNE 2013 â&#x20AC;˘ OIL & GAS INQUIRER

Of the 42 companies tracked, 20 recorded increases in their 2012 capital expenditures compared to 2011. Over the year, 22 of the companies tracked had capital expenditures greater than cash flow. Those companies spending most in excess of cash flow were: Pembina (a difference of $3.39 billion), AltaGas ($1.34 billion), Gibson ($352.33 million), Precision ($269.25 million) and Trican ($192.39 million). As a group, the 42 companies spent $5.43 billion in excess of cash flow.

Photo: Joey Podlubny

On the gas side, the producer group reported an overall decline in produc-

advertisers' index Advantage Valve Maintenance Ltd . . . . . . . . . . . . . . 65 Allmand Bros Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . .50 Annugas Compression Consulting Ltd . . . . . . . . . . . .42 Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 68 Bilton Welding and Manufacturing Ltd . . . . . . . . . . . 76 Brother’s Specialized Coating Systems Ltd . . . . . . . 45 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . . . . 46 Canadian Standards Association . . . . . . . . . . . . . . . .20 CG Industrial Specialties Ltd. . . . . . . . . . . . . . . . . . . .32 Chevron Delo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 City of Fort Saskatchewan . . . . . . . . .inside back cover City of Fort St John . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Clean Harbors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 57 CRD Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70 Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . . . . . . 47 Diversified Glycol Services Inc . . . . . . . . . . . . . . . . . .76 dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Do All Industries Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 49 DSI Thru-Tubing Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Eclipse Rentals Inc . . . . . . . . . . . . . . . . . . . . . . . . . . .65 Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . . . . . 75 Edmonton Exchanger & Manufacturing Ltd . . . . . . . . 77

JUNE 2013 • OIL & GAS INQUIRER

Environmental Refuelling Systems Inc . . . . . . . . . . . 38 Enviro Vault Canada Ltd . . . . . . . . . . . . . . . . . . . . . . . .5 Expertec Van Systems Inc . . . . . . . . . . . . . . . . . . . . .82 FlexSteel Pipeline Technologies Inc . . . . . . . . . . . . . 60 Foremost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 GPRC Fairview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 Grant Thornton LLP . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Hughson Trucking Inc . . . . . . . . . . . . . . . . . . . . . . . . .55 Industrial Training International . . . . . . . . . . . . . . . . 78 Kubota Canada Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . .3 MaXfield Inc . . . . . . . . . . . . . . . . . . outside back cover Maxxam Analytics . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 MDI Industrial Sales Inc . . . . . . . . . . . . . . . . . . . . . . .24 Meridian Manufacturing . . . . . . . . . . . . . . . . . . 36 & 37 MNP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . . . . .20 MRC Global Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 NAIT Corporate and International Training . . . . . . . . 27 NC Services Group Ltd . . . . . . . . . . . . . . . . . . . . . . . 46 NETZSCH Canada Inc . . . . . . . . . . . . . . . . . . . . . . . . 40 Norseman Structures . . . . . . . . . . . . . . . . . . . . . . . . .25 Northgate Industries Ltd . . . . . . . . . . . . . . . . . . . . . .26 Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . . . . 49

OilPro Oilfield Production Equipment Ltd . . . . . . . . .26 Pelican Products ULC . . . . . . . . . . . . . . . . . . . . . . . . 44 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 PTI Group Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Pumps & Pressure Inc . . . . . . . . . . . . . . . . . . . . . . . . .47 Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . . . . . . 79 Schneider Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Shaw Cablesystems Ltd . . . . . . . . . . . . . . . . . . . . . . . .4 STEP Energy Services . . . . . . . . . . . . . . . . . . . . 48 & 58 Systech Instrumentation Inc . . . . . . . . . . . . . . . . . . . .9 Tank Gauging Systems . . . . . . . . . . . . . . . . . . . . . . . . 57 The Modern Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 TOG Systems-Telecom Oil + Gas . . . . . . . . . . . . . . . . .59 TransGas Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . .63 Tundra Process Solutions Ltd . . . . . . . . . . . . . . . . . . 39 Unified Valve Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Veyance Technologies Inc . . . . . . . . . . . . . . . . . . . . . . 31 V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . . . . 12 Westeel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Yantai Jereh Petroleum Equipment Technologies Co Ltd . . . . . . . . . . . . . inside front cover Zeeco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

seizing

industrial opportunity

For business expansion or relocation information contact Economic Development at:

780.992.6231 or visit www.fortsask.ca

TOGE THE R WE CAN

For over 10 years MaXfield has quietly been gaining the expertise and experience to handle your next project. From custom vessels to structural steel, piping and modular packaged equipment; MaXfield is now your one stop shop for industrial fabrication.

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