Oil & Gas Inquirer July 2014

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INQUIRER Western Canada's Exploration & Production Authority

BIG WHEELS TURNING Oilfield haulers track ups and downs in industry capital spending, while awaiting gas drilling uptick

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OILweek 4/14

CONTENTS

JULY.

in the news

9

Stronger gas price may add $6 billion to producer cash flow

regional news

13

British Columbia

21

Northeastern Alberta

27

Southern Alberta

Montney gas transportation planning crucial, says ARC

Jackfish continues to be success story for Devon

Legacy pushing waterfloods at Turner Valley

17

23

29

Northwestern Alberta

Long Run increasing waterflood testing in Montney

Central Alberta

Duvernay JV partner would help Talisman appraise and develop wider area of the play

Saskatchewan

Crescent Point reports strong first quarter

features

COVER

FEATURE

32 Big wheels turning Oilfield haulers track ups and downs in industry capital spending, while awaiting gas drilling uptick

every issue

6 39

Stats at a Glance Political Cartoon

35 Liquids central Operators in west-central Alberta are in development mode in Cardium and NGL plays, while chasing new opportunities

Cover design: Peter Markiw Photo: Anatoliy Kosolapov/Thinkstock.com

O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

3

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TSX-V:ENT

Editor’s Note Vol. 26 No. 1 EDITORIAL EDITOR

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

Carter Haydu, Richard Macedo, Pat Roche, Elsie Ross, Paul Wells

A golden age for railways

EDITORIAL ASSISTANCE MANAGER

Tracey Comeau | tcomeau@junewarren-nickles.com EDITORIAL ASSISTANCE

Kate Austin, Shawna Blumenschein, Sarah Eisner, Katy Jones, Sarah Maludzinski CREATIVE PRINT, PREPRESS & PRODUCTION MANAGER

Michael Gaffney | mgaffney@junewarren-nickles.com

Railways are an 18th-century technology that’s

1.69 billion pounds in 2007 to 5.84 billion pounds

CREATIVE SERVICES MANAGER

making a major comeback in the 21st century.

in 2012 and is expected to soar to 12.45 billion

Driving that comeback is the Canadian oil and

pounds in 2017.

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

Cathlene Ozubko GRAPHIC DESIGNER

Peter Markiw

gas industry.

Difficulty in building new export pipelines

Railways are responding to this demand by shipping unit trains of frac sand across the

means increasing volumes of oil are going

continent. In early June, Source Energy Services

to be transported by rail, according to the

and Canadian National Railway Company (CN)

SALES

Canadian Association of Petroleum Producers’

announced a 100-car unit train of frac sand

SALES MANAGER—ADVERTISING

(CAPP’s) 2014 Crude Oil Forecast, Markets &

arrived in Grande Prairie, Alta., from Wisconsin.

SENIOR ACCOUNT EXECUTIVES

Transportation.

This equals around 10,000 tons of sand.

CREATIVE SERVICES

Ginny Tran Mulligan production@junewarren-nickles.com

Monte Sumner | msumner@junewarren-nickles.com Nick Drinkwater, Tony Poblete, Diana Signorile SALES

CAPP forecasts that crude moving by rail

CN thinks this is just the beginning as

Rhonda Helmeczi, Sammy Isawode, Mike Ivanik,

will more than triple —to about 700,000 barrels

operators begin ramping up for liquefied natural

Nicole Kiefuik, Gerry Meyer, James Pearce

per day in 2016 from 200,000 barrels per day in

gas exports out of British Columbia, said Jean-

For advertising inquiries please contact adrequests@junewarren-nickles.com

2013. Current rail-loading capacity originating

Jacques Ruest, the railway company’s executive

in western Canada has increased to 300,000

vice-president and chief marketing officer, at the

barrels per day from about 180,000 barrels at

company’s fi rst-quarter release.

AD TRAFFIC COORDINATOR—MAGAZINES

Lorraine Ostapovich | 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

the beginning of 2013. In January 2014, there

“They drill, they frac and cap,” he said.

were more than 17,000 Canadian rail-tank-car

“They’re already moving pipe and frac sand to

loadings of crude oil and petroleum products.

northern B.C. to build up a base of readily avail-

Several large unit train–loading facilities

able gas.”

have been announced for western Canada, and

Even once a project gets the green light, it

Ian MacGillivray | imacgillivray@junewarren-nickles.com

these could be in operation by the end of 2015,

takes years to build, he said. “Then there will

DIRECTOR OF THE DAILY OIL BULLETIN

increasing western Canadian rail uploading

be a huge amount of drilling, a huge amount

capacity for crude oil to more than one million

of frac sand—and by huge, we mean unit

Gord Lindenberg | glindenberg@junewarren-nickles.com

barrels per day. Add in proposed facilities, and

train quantity.

DIRECTOR OF CONTENT

that number could climb to 1.4 million barrels

DIRECTOR OF EVENTS & CONFERENCES

Stephen Marsters | smarsters@junewarren-nickles.com DIRECTOR OF DIGITAL STRATEGIES

Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION

Audrey Sprinkle | asprinkle@junewarren-nickles.com DIRECTOR OF FINANCE

per day.

The unconventional oil and gas boom is

“That’s where the market is heading in western Canada, as it is in Texas. People want to ship 50-railcar blocks of frac sand, and

Ken Zacharias, CMA | kzacharias@junewarren-nickles.com

also increasingly depending on rail to deliver

eventually leading to 200-car blocks, with

OFFICES Calgary

materials across the continent. According to

high-efficiency, high-scale operations. All of

the Freedonia Group, Inc., the quantity of sand

this means a lot of good things for railroads

used in North America increased to 53.6 billion

and...for CN, whether it’s manufacturing or the

pounds in 2012 from 12.3 billion pounds in

resource itself.”

2nd Flr-816 55 Avenue N.E. | Calgary, Alberta T2E 6Y4 Tel: .. | Fax: .. Toll-Free: 1.800.38.2446

Edmonton

220-9303 34 Avenue N.W. | Edmonton, Alberta T6E 5W8 Tel: 0.. | Fax: 0..00 Toll-Free: .00..46

1997. The forecast is for consumption to grow to

SUBSCRIPTIONS Subscription Rate

growth rate will be in Canada, at 16.3 per cent

In Canada, 1 year $4 plus GST, 2 years $6 plus GST Outside Canada, 1 year $

93.9 billion pounds by 2017. The highest annual per year. In Canada, proppant demand grew from

Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com

Subscription Inquiries Telephone: 1.866.543.888 Email: circulation@junewarren-nickles.com Online: junewarren-nickles.com GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-441 | © 2014 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 4006240.

Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 2nd Flr-816 55 Avenue N.E., Calgary, Alberta T2E 6Y4.

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.

N EXT I S S U E August 2014 Charting midstream expansions in Alberta, plus LNG pre-drilling in northeastern B.C.

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.

O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

5

FAST NUMBERS

.

.

million barrels per day

CAPP forecast for oilsands production in 2030.

million barrels per day

CAPP forecast for conventional oil production in 2030.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

M O NTH

OIL

GAS

OTHER

T O TA L

MONTH

OIL

GAS

D RY

SERVICE

T O TA L

Jun 

1

14

3



Jun 

23

56

1

5



Jul 

263

5

51



Jul 

61

103

15

51



Aug 

34

46

34



Aug 

81

2

1

3



Sep 

35

2

2



Sep 

35

113

1

30



Oct 

528

153

2



Oct 

53

204

8



,

Nov 

463

164

44



Nov 

852

218



62

,



Dec 

65

180

20

2



488

156

18

55



8

163

15

3

,

Dec 

28

13

52

Jan 

280

105

5



Jan 

Feb 

42

11

80



Feb 

Mar 

521

165

126



Mar 

24

218

23

118

,

Apr 

418

4

62



Apr 

504

142

1

68



May 

188

54

63



May 

25



10

5



Wells Drilled in British Columbia

Saskatchewan Completions

Source: BC Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

OIL

GAS

Jun 

80

0

2



Jul 

358

1

13



405

Aug 

362

1

6



422

Sep 

34

0

1



Oct 

380

0

15



Nov 

33

0

2



Dec 

321

0

3



Jan 

181

0

13



Feb 

401

0





Mar 

34

0

14



Apr 



0

23



May 

20

0

1



Jun 

45

330

Jul 

4

3

Aug 

26

Sep 

43

Oct 

52

44

Nov 

58

532

Dec 

45

45

Jan 

4

4

Feb 

46

150

Mar 

55

205

Apr 

56

261

May 

41

302

*From year-to-date

MONTH

OTHER

TOTAL

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J U LY 2 0 1 4 • O I L & G A S I N Q U I R E R

STATS

AT A

GLANCE

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, June 11, 2014 Source: Rig Locator

Alberta, May 2014 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 Alberta British Columbia

Manitoba Saskatchewan WC TOTAL

OIL WELLS

Alberta

May 

GAS WELLS

May 

May 

May 

11

35



30%

Northwestern Alberta

51

2

48

45

2

51



35%

Northeastern Alberta

65

5

0

0

2

13



13%

Central Alberta

65

8

5

3

4

1



51%

Southern Alberta



4

1

0







%

TOTAL









Horizontal Wells

Drilling Activity: CBM & Bitumen

Source: Daily Oil Bulletin

Alberta, May 2014 Source: Daily Oil Bulletin

MONTH

ALBERTA

SASK ATCHEWAN

BRITISH COLUMBIA

MANITOBA

January

482

28

5

41

Alberta

February

483

331

66

44

Northwestern Alberta

0

0

6



March

453

16

6

23

Northeastern Alberta

0

0

65

5

April

300

1

5

0

Central Alberta

0

0

38

50

May

24

4

44

0

Southern Alberta

0

0

0

0

,







TOTAL









TOTAL

C OA L B E D M E T H A N E May 

May 

BITUMEN WELLS May 

May 

O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

7

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855.REDGUARD

IN THE

NEWS Issues affecting Canada’s E&P industry

Stronger gas price may add $6 billion to producer cash flow

By Pat Roche

Photo: Joey Podlubny

With higher prices, gas-oriented companies are beginning to drill more wells in western Canada.

Low North American storage levels mean natural gas prices are likely to remain strong through at least October, says Andrew Bradford, head of energy research with Raymond James Ltd. “Whatever we all thought gas prices were going to be in October, I’m sure it’s at least $1.25 higher than it was then, maybe even $1.50,” Bradford told a Petroleum Services Association of Canada (PSAC) lunch.

“A $1.25 means $6 billion in additional cash flow. That’s pre-royalties,” he told the lunch at which he released his fi rm’s prediction that 11,300 wells will be drilled in the Western Canadian Sedimentary Basin this year, up from 11,032 last year.

That’s marginally higher than PSAC’s updated 2014 forecast of 11,170 wells— which includes 20 in northern and eastern Canada, including offshore.

Bradford expects the net impact of producers getting an extra $1.25 per thousand cubic feet for their gas this year will increase producer cash flow by about eight per cent.

And any increase in producer cash flow is typically directed toward the drill bit, which is good news for the service sector.

Over the last couple of years, producers have been drilling more gas wells and fewer oil wells, said Bradford.

In the first quarter, there were 750 wells licensed to drill for gas in the three most western provinces, up from 588 and 476 in the corresponding periods of 2013 and 2012, respectively. And during all of 2013, 2,263 drilling permits were issued for gas in the three most western provinces, up from 1,862 in 2012.

Daily Oil Bulletin completion data (where a status has been assigned to a well) also shows a higher percentage of wells in the first quarter with gas as the final status compared to the first quarter of 2013.

“Oil has been in decline for two years, but gas-based drilling is on the upswing,” said Bradford. He cited two factors aiding the revival in gas drilling—producers have been chasing liquids-rich gas and some are doing large programs with multi-well pads, which tend to go year-round.

Bradford displayed two side-by-side charts, one showing roughly 100 rigs working in the Montney gas play in the first quarter of this year—by far the highest of

any of the 13 quarters on the bar graph.

The other chart showed the rig count in the Viking oil play at less than 30 in the fi rst quarter of 2014, down from more than 40 in the third quarter of 2011.

According to the Raymond James presentation, rig counts are lagging in two other oil plays. The Cardium rig count was down in 2013 and flat in the fi rst quarter of 2014 compared to the same quarter last year. And the Saskatchewan Bakken rig count was down last year and is down so far this year.

Referring to the drop in oil drilling and the gain in gas-directed activity, Bradford asked his service sector audience, “Now how much does this matter? Do you really care if one rig count is going up or down with respect to the other? I’d say, yeah—yeah, we should care a lot. We should definitely care a lot.”

That’s because, on average, gas wells are much deeper and more likely to have complex orientations—both of which require significantly more capital than shallow vertical wells. Bradford displayed a graph showing the average measured depth of Canada’s gas wells has grown to more than 3,500 metres, while the average measured depth of Canadian oil wells remains well below 2,000 metres.

The deeper and more complex the well, the more revenue it generates for the service sector.

Bradford said conventional crude oil prices in the $90–$105 range should be strong enough to sustain oil drilling activity. But a number of smallish or mid-size producers have chosen to pay out a chunk of their cash flow in dividends, reducing the amount available for drilling budgets.

While western Canada’s total rig count will be challenged by slowly declining crude development programs, gas-based drilling “is almost certain to grow,” he said.

The analyst predicts the total metres dr i l led— a nd ser v ice revenue —w i l l increase even if the rig count stays flat.

Also, he expects the seasonal variations in the rig counts to become less extreme.

O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

9

In The News

Pipeliners on hook for any leaks

By Carter Haydu

Federally regulated pipeline companies will be liable for up to $1 billion of costs and damages in the event of a spill, Canada’s Natural Resources Minister Greg Rickford announced in May. “The ‘polluter pays’ principle will now be enshrined in law, so that it is clear Canadian taxpayers are not expected to foot the bill in the event of a major oil spill,” he said during a conference call.

“The government will also strengthen the liability and compensation offered by pipeline companies in a number of important respects. First, pipeline companies will be held fully liable in all incidents, whether or not they are at fault or negligent. This approach is called ‘absolute liability,’ and it will apply to all federally regulated pipelines up to $1 billion for companies operating major pipelines.”

The new measures provide the National Energy Board (NEB) with authority to order reimbursement of any clean-up costs incurred by governments, communities or individuals. Further, the NEB will have the authority and resources to assume control of incident response if a company is unable or unwilling to do so.

The new measures, including materials, construction methods and emergency response techniques, give the NEB the ability to provide guidance on the use of the

best available technologies used in federally regulated pipeline projects.

Finally, the government will develop a strategy with industry and aboriginal communities in an effort to increase the participation of First Nations in pipeline safety operations, including planning, monitoring, incident response, and related employment and business opportunities.

“We will also strive to ensure meaningful aboriginal participation in pipeline safety activities and modernizing the National Energy Board act in the interests of ensuring our pipelines are safe for Canadians and safe for the environment,” Rickford said, adding the pipeline safety changes strengthen environmental protection, enhance aboriginal engagement and streamline the review process of major resource projects.

The announcement came one day after Transportation Minister Lisa Raitt announced measures to st reng t hen Canada’s tanker safety and address concerns about oil spills, which includes modernizing Canada’s marine-navigation system and strengthening the polluter pays principle.

According to Raitt, about a year and a half ago, the federal government began the process that led to the announcements, with recommendations offered by an independent expert panel.

"Canadian taxpayers are not expected to foot the bill in the event of a major oil spill.”

— Greg Rickford, natural resources minister

“We want to be world class, and we want to be leading edge in making sure that if we are going to transport whatever goods it is, in whatever mode of transportation it is, rail included, that we do it as safely as we possibly can,” she said.

Rickford said the regulations are not in response to any specific proposed pipeline project that would move Alberta crude to the West Coast. He said the new measures deal with future pipelines, as well as existing ones. He noted the liability to be placed on companies is not arbitrary.

“It is 200 times what we know to be the average cost of a spill. We think that puts Canada ahead of the world in two important regards. First of all, this is the fi rst of its kind. Second of all, the multiplier on the average cost of a spill, remote and rare as that might be, puts us out in front of everybody,” he noted.

Exploratory metres drilled at 20-plus-year low A record amount of development metres has been rig released in western and northern Canada from January to April 2014, at close to eight million metres, while exploratory meterage is at a 20-plus-year low.

Operators rig released 7.95 million metres of development hole to the end of April, up from the previous high of 7.05 million metres last year.

Meanwhile, producers drilled 993,608 metres of exploratory hole in the first four months of 2014, off from 1.13 million metres last year and the first time in 22 years that the amount has fallen below one million metres in the January-to-April period.

In the fi rst four months of 1992, there were 840,950 exploratory metres rig released in western and northern Canada.

The average depth and length of an exploratory well increased to a record 2,799 metres, however, up from 2,682 metres last year.

There were a total of 355 exploratory wells rig released in this year’s four-month interval, a decrease of 16 per cent from 423 in the comparable period last year and the lowest tally since the Daily Oil Bulletin began tracking these statistics in 1988.

The average depth and length of an exploratory well increased to a record 2,799 metres, however, up from 2,682 metres last year.

In April, in a fi rst for that month, operators rig released over one million metres of development hole. At 1.05 million metres, the meterage tally was up significantly from 730,869 metres in April 2013.

— DAILY OIL BULLETIN

10

J U LY 2 0 1 4 • O I L & G A S I N Q U I R E R

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B.C.

BRITISH COLUMBIA WELL ACTIVITY MAY/13

MAY/14

Wells licensed

8



MAY/13

MAY/14

Wells spudded

25



MAY/13

MAY/14

31



Rigs released

▲

▲

British Columbia

▲

Source: Daily Oil Bulletin

Montney gas transportation planning crucial, says ARC

Photo: Joey Podlubny

As it ramps up its Montney production in northeastern British Columbia, ARC Resources Ltd. has been spending a lot of time working on how those future natural gas volumes will get to market, company shareholders heard in May. “The word for us is to be thinking five and 10 years ahead,” Myron Stadnyk, president and chief executive officer, told the company’s annual meeting.

“You start looking at LNG [liquefied natural gas] coming on and starting to

A lot more new pipe needs to be installed if LNG exports become reality, says ARC president and chief executive officer Myron Stadnyk.

predict those volumes,” he said. “The area towards B.C. and past Grande Prairie, [Alta.], where the least amount of pipe extending is where the most amount of gas is coming from.”

To ensure transportation for its new Montney gas plants that are now coming on stream, ARC had to take marketing contracts three or four years ago when TransCanada Corporation extended its NOVA Gas Transmission Ltd. (NGTL) line into British Columbia, the meeting heard.

“So our thinking on the gas side was well ahead,” said Stadnyk For the future, the company is keeping a keen eye on NGTL’s proposed North Montney pipeline, as it will run near ARC’s Attachie property, Stadnyk said.

The pipeline would connect to the existing Groundbirch Mainline (Saturn section), about 35 kilometres southwest of Fort St. John, B.C., and will continue for about 187 kilometres northwest of Fort St. John.

On the oil side, oil from Tower can be trucked to a terminal where it is put into a pipeline and more than 95 per cent of production is eventually moved by pipeline.

Although trucking costs have gone up from about 50 cents per barrel to about $2 per barrel, the increased cost has been off set by higher netbacks, he said.

ARC recently signed longer-term contracts with Pembina Pipeline Corporation and Keyera Corp. that will enable it to move 5,000 barrels per day of propane, butane and lighter crude, including one 3,500-barrel-per-day contract.

Stadnyk also said ARC has concluded that diversifying its physical markets is serving it well. Of the 350 million cubic feet

per day of gas that it is producing, about 220 million cubic feet clears at AECO, 80 million cubic feet flows on Spectra, and the company is starting to direct market to potash mines in Saskatchewan. It has also shipped some gas on the Northern Border Pipeline to the Chicago market.

“On the gas side, we are deriving price benefit by being thoughtful about physical diversification,” he said. In February, for example, ARC was able to obtain a price of $13 per thousand cubic feet for gas, which at the time was trading in the $4-plus range in Alberta.

W hile A RC historically has been a nat ural gas producer, it is cur rent ly producing 44,000 barrels per day of liquids, up 50 per cent from 2011, shareholders heard. “As gas prices have been falling, our cash flow per share has been doing very well because we are building a very efficient oil business in behind our gas business,” said Stadnyk.

A RC has 900 net sections in the Montney Formation between Ante Creek in Alberta to Attachie, with current production of about 66,000 barrels equivalent per day, heading to 88,000 barrels per day. In northeastern British Columbia, the company has drilled 350 wells since it drilled the first horizontal well in British Columbia in 2005, and production has risen to 47,500 barrels equivalent per day.

Stadnyk described the rates of return for the Montney as “tremendous,” ranging from 35 per cent at Tower to 85 per cent at Dawson and 70 per cent at Ante Creek.

As ARC continues to invest heavily in the Montney, it’s important that it thinks about how it compares to the other key plays, he said.

“We are not competing with other parts of Alberta anymore, we are competing with the Marcellus in Pennsylvania, with the Eagle Ford,” said Stadnyk. “We have spent a lot of time benchmarking those plays this year, and we are in O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

13

British Columbia

the best-of-the-best Montney, and those Sunrise wells are competing with the best counties in the Marcellus.”

At Sunrise, wells are on track to produce 15 billion cubic feet per well from multiple zones in the same Montney Formation, he told the meeting. “At $3 [per thousand cubic feet] gas, that’s a 50 per cent rate of return.”

When it comes to wells, it’s all about quality, according to Stadnyk.

A lot of producers talk about initial production rates, “but we like to think longer term,” he said. More than 1,200 wells have been drilled in the Montney, and ARC wells in the first year produced about 70 per cent more product than other wells in the basin, said Stadnyk. ARC’s average well produced 3.95 million cubic feet per day in the fi rst year compared to 2.34 million cubic feet per day for the average well. “That’s a

tribute to the technology throughout our teams, to our geologists and our operations and engineering people for bringing it all together for us,” he said.

Last year was also the sixth in which ARC replaced more than 200 per cent of production through the drill bit. It has identified more than 3,000 drilling locations in the Montney.

— DAILY OIL BULLETIN

Painted Pony ready for LNG exports, continues improving completions technologies

By Carter Haydu

When it comes to positioning for possible liquefied natural gas (LNG) exports, Painted Pony Petroleum Ltd. believes its Montney assets are in the right place at the right time.

“We can feed into any one of these LNG projects that are planned on Canada’s West Coast—Prince Rupert, Kitimat and even down around Vancouver,” Patrick Ward, president and chief executive officer, told the company’s annual general meeting.

Ward said the fact that Painted Pony will not have to build pipelines because one would already be available will save the company a lot of cash. Most companies must spend “tens of millions of dollars” to accomplish the same connectivity, which bodes well for the long-term value of his company, he said According to Ward, there are plenty of reasons to believe Canada’s LNG industry is going to see substantial growth as well, benefiting Painted Pony’s conveniently located, high-pressure Montney assets.

“What is the advantage for Canada being in LNG? One is that we are close to Japan. I know it doesn’t seem that close, but compared to some of the other LNG suppliers in the world, we are quite close.

The only one tied with us is Australia, and so we can compete on a shipping distance.”

Canada is at an advantage over many natural gas–producing regions due to the colder climate in British Columbia, which makes the actual liquefaction process more efficient and cost effective, Ward noted.

14

J U LY 2 0 1 4 • O I L & G A S I N Q U I R E R

“The ambient temperature at Kitimat and Prince Rupert is about 6 [degrees Celsius] on average. If you look at the Gulf Coast of Mexico, it’s 26.5 [degrees Celsius]. If you look at Queensland, Australia, it’s about 27.5 [degrees Celsius].

In Qatar, it’s about 28.5 [degrees Celsius].

So it’s about that fi rst 20 [degrees Celsius] of cooling, and liquefaction is all about cooling gas down.

“It is really just a massive refrigeration process, and because it’s 20 [degrees

21

Number of wells Painted Pony plans for 2014

Celsius] cooler in B.C., it saves you about 20–30 per cent on energy costs. And you can also make more LNG in the samesized vessel because it is more efficient—is already coming in at a cooler temperature.

I like to use the ‘beer fridge’ example. If you’ve ever had one on your deck, you know it works a lot better in the winter than it does in the summer.”

In an effort to accelerate growth in its B.C. Montney initiatives, Painted Pony

recently increased its 2014 capital expenditures budget by 22 per cent to $169 million.

“We’re drilling about double the number of wells that we did last year into the Montney,” Ward said. “Operationally, we’re up to six net wells that we have drilled to date. We’ve completed six Montney wells, and we have had fantastic results on our completions.”

The revised budget includes a total of 21 (19.5 net) wells in 2014, as well as construction of a planned 25-millioncubic-feet-per-day natural gas compression and dehydration facilit y at Blair in the fourth quarter, with operations beginning in early 2015. Further, the company intends to double processing capacity at its 50 per cent working interest Daiber dry gas facility to 50 million cubic feet per day, with operations also to begin in the final quarter.

Regarding cost reductions from technology advances, Ward noted the company used ball-drop completion and traditional perf-and-plug on the A-91-F/94-B-16 well.

He said that over 240 days, the cumulative production from the ball-drop system was 1.154 billion cubic feet, compared to 852 million cubic feet from perf-and-plug. “ We’re get t ing bet ter recover ies because we’re reaching further out into the reservoir with this new technique,” he said, adding that using ball-drop actually saved the company about $750,000 per well, dropping completion costs by 20 per cent when compared to perf-and-plug.

British Columbia

Hybrid LNG price may work for some projects

By Pat Roche

Proposed West Coast liquefied natural gas (LNG) projects that own natural gas reserves have a big advantage because of reduced pricing risk, says Scotiabank vicepresident and commodity market specialist Patricia Mohr.

And while there has been debate over whether the price of LNG to be exported from Canada should be based on world oil prices (the sellers’ preference) or North American gas prices (the buyers’ preference), Mohr raised the possibility of a hybrid of the two.

Recent pricing developments, where some proponents of projects on brownfield—or partially developed—sites have agreed to sell LNG at North American gas-based prices, may pose a challenge for some proposed B.C. projects, Mohr told an IBC Energy LNG Export & Infrastructure conference in Calgary.

That’s because the 14 B.C. proposals are greenfield projects, where everything would have to be built from scratch. Hence why they would need a higher LNG price than projects developed on existing sites, such as Cheniere Energy, Inc.’s Sabine pass gas liquefaction plant in Louisiana and projects in Middle East countries like Qatar.

However, “hybrid pricing—rather than more lucrative 100 per cent oil-indexed prices—is possible for some B.C. projects,” Mohr wrote in her PowerPoint presentation.

But she cautioned: “In this environment it is vital that EPC [engineering, procurement and construction] contractors contain cost escalation for both liquefaction and new pipeline infrastructure, despite pressure on labour and material costs from competing projects in the Alberta oilsands and in the B.C. mining industry.”

She added, “While natural gas hubbased pricing currently yields lower profitability for sellers, natural gas prices across North America could be pulled up significantly later in the decade if large-scale LNG development receives U.S. Federal Energy Regulatory Commission approval in the U.S. Gulf.”

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Mohr believes the B.C. projects that don’t also own gas resources would be most challenged by hybrid pricing.

“But...the ones that are tied directly to ownership of natural gas assets have a big advantage because the pricing risk is really reduced tremendously,” Mohr said.

But pricing risk will never be entirely eliminated, she added, noting there will still be a pricing risk between the Asian gas price and the cost of delivering LNG to those markets.

Proposed LNG projects, whose proponents own vast gas resources, include those led by Royal Dutch Shell plc, Exxon Mobil Corporation, Chevron Corporation and Malaysia’s PETRONAS. Ten other projects are proposed for Canada’s West Coast.

“We don’t know what the pricing is under the various off-take

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even have a pricing contract.”

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

Mohr noted that PETRONAS has significantly de-risked its proposed Canadian LNG export project by bringing in very big Asian LNG buyers who took a stake in PETRONAS’s Montney gas assets, as well as the LNG project. These companies are Chinese integrated oil giant Sinopec Corp.

(15 per cent), Japan Petroleum Exploration Co., Ltd. (JAPEX) (10 per cent), New Delhi– based refining giant Indian Oil Corporation Ltd. (10 per cent) and PetroleumBRUNEI (three per cent).

“We don’t know what the pricing is under the various off-take agreements to JA PE X or Sinopec or Indian Oil or PetroleumBRUNEI...or whether or not, in fact, they even have a pricing contract,” Mohr said.

N.W.

NORTHWESTERN ALBERTA WELL ACTIVITY MAY/13

MAY/14

Wells licensed

18



MAY/13

MAY/14

Wells spudded

61



MAY/13

MAY/14

61



Rigs released

▲

▲

Northwestern Alberta

▲

Source: Daily Oil Bulletin

Long Run increasing waterflood testing in Montney

Photo: Joey Podlubny

By Pat Roche

Light oil–focused Long Run Exploration Ltd. will continue to use waterflooding to enhance oil recovery in its Peace River and Edmonton core areas, shareholders heard in late May. In its Peace River area the company expects to implement one waterflood pilot each in the Normandville and Girouxville a rea s, sa id pre side nt Da le M i l le r.

Implementation of both pilots is expected to happen this year, Miller told the company’s annual meeting.

“They’ll be full-pattern waterf lood pilots—it just isn’t going to be one injector a nd one producer,” he said. “ We’ve planned for Normandville, I believe, eight injectors, and at Girouxville, we’ll have four injectors with a complement of producers. So we’ll have two real-goodpattern waterflood pilots.”

Normandville and Girouxville are in the Montney oil fairway.

In the company’s Edmonton (central Alberta) area, the primary targets are Viking/Mannville and Mississippian light.

Long Run started a waterflood pilot in the Viking Formation at Redwater last December. “We’re just starting to get some reservoir fill-up, and we’ll see how that responds throughout the year,” Miller said.

He said the company will expand that pilot and implement a second waterflood pilot at Redwater in the third or fourth quarter of this year.

By year’s end, Long Run will have two waterflood pilots in the Viking and two in the Montney.

Meanwhile, the company has also been growing by the drill bit.

Production from its Peace River area has grown to about 11,000 barrels equivalent per day (60 per cent oil and natural gas liquids), up from about 7,500 barrels per day (30 per cent liquids), when the current manage me nt , wh ic h includes chief executive officer William A ndrew, took over in August 2011, Miller said.

Close to 9,50 0 – 10,000 barrels per day of Long Run’s Long Run’s Peace River production has grown to 11,000 barrels equivalent per day.

Peace River area production comes from Normandville and Edmonton region is Cherhill, where the Girouxville, he said. primary target is Banff oil.

Long Run plans to drill 43 horizontal Miller said the combined output from Montney wells in its Peace River area this Redwater and Cherhill is about 7,500 baryear, 18 of which were drilled in the fi rst rels equivalent per day (75 per cent oil). He quarter. Miller said Long Run’s Montney said Long Run drilled about two dozen wells drilling times have been cut to six or seven in its Edmonton area during the first quarter days (spud to rig release), down from and expects to drill a total of 43 for the year.

11–12 days.

Long Run reported average first-quarter Besides t he Redwater Vik ing oil output of about 25,600 barrels equivalent play, the other focus area in Long Run’s per day.

O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

17

Northwestern Alberta

Kaybob Duvernay hotspots, says Athabasca

By Richard Macedo

The Kaybob area looks to be the most promising area for the Duvernay so far, according to Athabasca Oil Corporation, which is expected to expand its drilling program in the emerging shale play later this year.

Sveinung Svarte, president and chief executive officer, said the company plans to increase its Duvernay activity when PetroChina Company Limited’s Phoenix Energy Holdings Limited put/call is “in the bank.” In May, the company announced it is increasing its capital budget in 2014 by $29 million, which w ill include an expanded Duvernay drilling program in

the second half of the year. It also released Duvernay well results.

“The Duvernay deposits are very large.

Having said that, they are probably not excellent everywhere,” he told the company’s annual meeting. “Where we are located around Kaybob, it’s basically the place in the Duvernay where it looks to be the most promising so far.

“There’s a very large resource-in-place figure in these lands, at up to 700 barrels per million cubic feet of free condensate—very rich, and the initial results actually compare very favourably to what we know from the south, from the Eagle Ford,” he said.

In addition, Svarte said the company has a local market for the condensate.

“We actually sell it normally at a premium, not as a discount,” he noted. “It goes to diluent in the oilsands.”

In total, Athabasca has now drilled eight horizontal Duvernay wells across the fairway, with four wells on production at the end of the first quarter of 2014.

The 08-29 horizontal is planned to be on stream in July 2014, the 04-29 is also planned to be on stream that month, while the 16-36 is planned for completion in the third quarter of 2014 and is expected to be on stream in January 2015.

Encana says North Duvernay commercial

By Pat Roche

Encana Corporation has deemed its liquidsrich Duvernay plays in the Kaybob and Simonette areas commercial, a conference call heard in May. When asked whether the company’s Duvernay wells in northwestern Alberta can be considered commercial, Encana president and chief executive officer Doug Suttles replied: “What we’ve done is distinguished the northern part of our position versus the southern. So the Kaybob/ Simonette area we consider commercial today, and that’s why we are moving forward on two eight-well pads.

“In the south—an area we refer to as Willesden Green—we’re still in appraisal there and we haven’t made that decision.

But in the northern part of the Duvernay, we consider both of those areas very commercial, very attractive places to invest,” Suttles said while discussing the company’s first-quarter results with analysts.

In the fi rst quarter, Encana’s Duvernay production averaged 1,400 barrels per day of oil and natural gas liquids and eight million cubic feet per day of gas.

The two eight-well pads were spudded during the first quarter. Equipment and supplies were stockpiled to enable the running of five rigs and continued facility construction through spring breakup.

Executive vice-president and chief operating officer Michael McAllister said Encana now has 10 horizontal wells that are being tested or are on production in the Kaybob/Simonette area.

“Some of these wells date back to 2012, and the results have continued to improve over time,” he told the conference call.

When asked about oil and natural gas liquids yields, McAllister said: “What we’re seeing is improved liquid-to-gas ratios up in our northern portion of the Simonette area.

We’re actually in the volatile oil window there. So liquids are looking a little richer than what we had originally anticipated— we’re seeing up to 400 barrels per million cubic feet, whereas I think we had mapped that out as 150 barrels.”

During the quarter, midstream solutions for the Duvernay were advanced with a five-year commitment from Encana and joint-venture partner Phoenix Duvernay Gas for transportation on the Alliance Pipeline and a five-year rich gas sale of up to 195 million cubic feet per day to Aux Sable Canada LP. Six wells have been completed with different versions of Encana’s high-intensity stimulation, with five of the six on or above type curve (100–130 per cent of type curve with a range of 14–350 days of history).

Liquids yield remains strong with three of the wells over 300 barrels per million cubic feet.

Apache expands out from Bluesky Formation at Kaybob Apache Corporation says it broug ht its f irst hor izontal Mont ney liquidsrich well in the Wapiti area online and drilled its second liquids-rich Duvernay wel l i n t he K aybob a rea, bot h w it h 18

J U LY 2 0 1 4 • O I L & G A S I N Q U I R E R

encouraging results, in the first quarter of 2014.

Production in Canada was 88,310 barrels of oil equivalent per day in the three months ended March 31, 2014, off from

110,368 barrels per day in the first quarter of 2013.

Apache reported record production at Kaybob during the first quarter of 2014.

Eight wells were spudded in the Bluesky

Northwestern Alberta

Formation and five have been completed, with an average test rate of 4.7 million cubic feet per day and average liquids yields of 67 barrels per million cubic feet.

Total liquids production in Canada averaged 25,358 barrels per day for the first quarter, up 10 per cent from the fourthquarter volumes of 22,965 barrels per day, due to successful horizontal drilling in House Mountain and new liquids-rich production from the West 5 and Kaybob Bluesky areas. First-quarter 2013 oil and liquids volumes were 23,839 barrels per day.

On April 30, 2014, Apache completed the sale of its Ojay, Noel and Wapiti areas in Alberta and British Columbia. These are primarily dry gas–producing properties comprising 622,600 gross acres (328,400 net acres).

In the Wapiti area, Apache will retain 100 per cent of its working interest in horizons below the Cretaceous, including rights to the liquids-rich Montney and other deeper horizons.

In 2013, production from the fields to be divested averaged 101 million cubic feet

88,310 barrels of oil equivalent per day Apache’s Canadian production

per day of natural gas and 1,500 barrels per day of liquid hydrocarbons (18,400 barrels equivalent per day).

During the first quarter, K itimat Upstream (50/50 partnership between

Apache and Chevron Corp. on Horn River and Liard Basin assets) production in the Horn River and Liard basins averaged 58 million cubic feet per day net to Apache’s interest, down eight per cent from the fourth quarter of 2013, due mainly to a planned shut-in for pad drilling (D-28-B horizontal) and well testing in both basins, plus natural declines.

Six rigs were drilling at the end of the first quarter, including three on vertical tenure wells; one on the 28-B horizontal tenure/production well, which is scheduled to be on production in the fourth quarter; one on the three-well horizontal 13-K South Pad, expected to rig release in early 2015; and one on the seven-well horizontal 3-K North Pad, which has an expected rig release date of fourth-quarter 2015. No wells were drilled for production during the quarter.

Operations started on the 2013-14 winter 3-D seismic programs in the first quarter, with a 515-square-mile acquisition expected to be completed by early in the second quarter of 2014.

— DAILY OIL BULLETIN

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O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

19

NORTHEASTERN ALBERTA WELL ACTIVITY MAY/13

MAY/14

Wells licensed

142



MAY/13

MAY/14

Wells spudded

142

 ▼

MAY/13

MAY/14

144

 ▼

Rigs released

▼

Source: Daily Oil Bulletin

N.E.

Northeastern Alberta

Jackfish continues to be success story for Devon

By Paul Wells

Devon Energy Corporation’s 25,000-barrelper-day Jackfish 3 project remains on target for first steam in the third quarter and signals the continuation of solid thermal heavy oil growth going forward, according to company officials.

“The start-up of our Jackfi sh 3 facility later this year will commence another leg of multi-year production growth from our thermal oil business. In 2015, we expect net oil production from our Jackfi sh complex to increase to a range of between 62,000 and 67,000 barrels per day, representing a year-over-year growth rate of approximately 30 per cent,” president and chief executive offi cer John Richels told the company’s fi rst-quarter conference call.

He added that the completion of Jackfish 3 will lower Devon’s overall capital intensity and begin an era of free cash flow for the Jackfish complex, “with the potential to generate up to $1 billion” annually for many years.

“This wall of cash provides a significant source of capital for E&P [exploration and production] investment, debt reduction, dividends and share repurchases,” Richels said.

Construction during phase one of the Jackfish project.

David Hager, chief operating officer, confirmed that construction of Jackfish 3 is essentially complete and “plant commissioning activities are well underway.”

He said delivery of fi rst oil is scheduled to occur late this year, with production ramping up throughout 2015.

First-quarter gross production from the Jackfi sh 1 and Jackfi sh 2 thermal oil projects averaged 62,000 barrels of oil per day in the first quarter, a nine per cent increase compared to the same period last year.

After accounting for royalties, net production from the company’s Jackfish complex averaged 52,000 barrels per day.

First-quarter results were highlighted by the excellent performance at Jackfish 1, where gross production exceeded nameplate facility capacity averaging 37,000 barrels per day.

“Recently, we have seen excellent results from efficiency modifications to our steam generation, lowering steam c ha mber pre ssu re s, opt i m i zi ng t he temperature profile in the steam chamber and conducting well stimulations,” Hager added. “Continued success from these and other efforts under way to lower our steam-oil ratio could result in continued growth in production above nameplate capacity.”

At peak production, Devon’s three 100 per cent owned Jackfish projects are expected to produce 105,000 barrels per day.

At Pike, a proposed thermal oilsands 50/50 joint-venture project with BP Canada Energy Group ULC and operated by Devon, the company expects to make a decision on the fi rst phase and receive regulatory approval later this year. Pike 1 will have ultimate gross production capacity of 105,000 barrels of oil per day.

“The approval process for the first phase of the Pike development remains on track, and we expect to receive regulatory approval this year,” Hager said.

Oilsands expected to create almost 100,000 jobs in next decade Photo: Joey Podlubny

By Elsie Ross

An estimated 98,380 jobs in oilsands construction, maintenance and operations will be generated over the next decade, highlighting the need for the construction and oil and gas industries to work together to ensure a supply

of skilled workers, says a new report called Oil Sands Construction, Maintenance and Operations Labour Demand Outlook to 2023.

Released in May, the report takes a unique approach to assess demands for

skilled workers by bringing together data and insights from the construction and oilsands sectors, as well as government.

The report estimates that the oilsands sector will generate about 72,810 direct O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

21

Northeastern Alberta

The report also says that as workers retire, attrition has the potential to drive a significant number of job openings over the next decade. Alberta could lose 37,500 skilled construction workers and 6,400 in oilsands operations due to retirements in that period.

construction and operations jobs this year.

Approximately 64 per cent, or 46,260 of the jobs, are within “aggregated oilsands construction,” which includes off-site prefabrication and modular construction, onsite construction and sustaining, ongoing and turnaround maintenance.

The remaining 36 per cent, or about 26,550, are direct oilsands operations jobs, supporting in situ, mining and upgrading production. Occupations facing the greatest job increases due to industry activity in oilsands operations are power engineers, heavy equipment operators and petroleum engineers, the report found.

Over the next decade, employment within oilsands operations is expected to grow by 15,330 new jobs, for total employment of about 41,880. More than 10,000 new jobs are projected for in situ operations, a 91 per cent increase over 2014 employment levels.

The workforce requirements for ongoing or day-to-day maintenance of oilsands operations will grow by 45 per cent, to 11,480 jobs in 2020 from 7,910 jobs in 2014, with a projected steady annual increase of

about 500 jobs as new projects move from the construction phase into the operations phase across the projection period.

Based on the current oilsands production forecast, the average annual aggregated oilsands construction workforce requirements will peak in 2019 at about 62,680 workers, an increase of 16,420 jobs, or a 35 per cent increase, over 2014 employment levels.

Construction jobs are expected to dip slightly after 2019 by 6,180 jobs if no additional oilsands expansion projects are announced.

The workforce required for on-site oilsands construction, turnarounds and ongoing maintenance will be around 48,710 workers in 2014, and will increase to about 56,900 jobs in 2020, a 17 per cent increase over 2014 levels. The workforce will peak at about 59,390 jobs in 2019.

The report also says that as workers retire, attrition has the potential to drive a significant number of job openings over the next decade. Alberta could lose 37,500 skilled construction workers and 6,400 in oilsands operations due to retirements in that period, it says.

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J U LY 2 0 1 4 • O I L & G A S I N Q U I R E R

CENTRAL ALBERTA WELL ACTIVITY MAY/13

MAY/14

Wells licensed

262



MAY/13

MAY/14

Wells spudded

31



MAY/13

MAY/14

22



Rigs released

▼

▲

▲

Source: Daily Oil Bulletin

C.A.B. Central Alberta

Duvernay JV partner would help Talisman appraise and develop wider area of the play

By Richard Macedo

A joint-venture partner wou ld help Talisman Energy Inc. appraise and develop a larger percentage of its Duvernay shale gas acreage, according to Hal Kvisle, president and chief executive officer.

The company currently holds interests in approximately 352,000 net acres of land in the liquids-rich Duvernay play located in central Alberta. During 2013, Talisman drilled three wells in the Duvernay play.

To date, 10 wells have been drilled, including two wells drilled in the first quarter of 2014, primarily to retain acreage. The company plans to pursue third-party funding, possibly through a joint venture, to develop the play going forward.

“We hold this enormous land position, and we literally have locations to drill several thousand horizontal wells. You can calculate how many billion dollars of capital that would work out to at roughly

Talisman has drilled 10 wells into the Duvernay.

$10 million or more per well,” Kvisle told Talisman’s annual general meeting.

Kvisle later told reporters that the magnitude of the Duvernay play is “not as understood as it should be.

“This is one of the most enormous things to have hit us,” he said. “It’s comparable to the Montney. I don’t know whether it’ll be as big or bigger or almost as big as the Montney. It’s very liquids rich and we and all of our industry competitors have to contend with deep horizons.

“The whole idea of the Duvernay is not that it’s a stinker of an asset that we’re trying to get out of; it’s rather we can either afford to fully appraise and develop 30 per cent of the land ourselves or, with a partner, we can appraise and develop 60 per cent,” Kvisle added. “As in any play, there’s probably a third of the land that would fall outside of the fairway that you want.”

Peyto pushing toward 100,000-barrel-per-day marker

Photo: Joey Podlubny

By Richard Macedo

In the first quarter of 2014, Pey to Exploration & Development Corp.’s production averaged over 72,000 barrels equivalent per day and, by 2017, it could crack the 100,000-barrel-per-day threshold.

The Deep Basin–focused, predominantly natural gas producer—for 2013, its output was weighted nearly 90 per cent to natural gas—has been able to grow production and maintain profitability by keeping its costs low, its annual general meeting heard in May.

“We continue to grow and build through the drill bit,” Darren Gee, president and chief executive officer, told the meeting.

During the fi rst quarter, the company spent $80.2 million to drill 31 (28.4 net) horizontal wells, and $36.1 million to complete 22 (21.5 net) wells.

For 2014, the company has a capital program of between $575 million and $625 million to drill 110–122 horizontal wells, increase processing capacity and natural gas liquids yield, increase its undeveloped

land base, shoot seismic and possibly make an acquisition.

The Deep Basin, the company noted, is a permeability trap because the fluids in the updip position can’t travel through the fine-grained, tightly compacted reservoirs, so there’s no risk of wells watering out.

Large resource potential in a concentrated, stacked package that can be developed with modern horizontal multistage fracturing well design allows the company to take advantage of pad drilling efficiencies.

O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

23

Central Alberta

Peyto operates 99 per cent of its production and processes 97 per cent of that through its nine owned and operated gas plants, and notes that “concentration and control are how you achieve low costs.”

The 2014 capital budget includes expansion work at four of Peyto’s gas plants. In total, it will have nine plants with over 600 million cubic feet per day of capacity.

“At Peyto, we do what we do because we believe in natural gas,” Gee said. “We believe it is the fuel of future.

“The reality is that the North American gas market is bigger than just Canada,” he added. “We have to be more efficient and more profitable than all of the other players in all the other plays in North America.

In fact, we don’t have to be just better, we have to be a lot better. When you look at where the population is, many of those plays have the advantage of being closer to the end-user than we are.”

In his monthly report for May, Gee noted that, lately, there’s been debate about the ability of western Canadian natural gas reserves to compete in the North American market, “especially when you consider that

their geographical location currently puts them at a disadvantage.”

Fiscal regimes in western Canada’s provinces are more attractive than in other basins in North America, which helps to level the playing field for gas plays, he added.

Referencing a netback analysis from Peters & Co. Limited, Alberta competes with both the Marcellus and Eagle Ford, primarily due to lower royalties. That’s because Alberta has a royalty regime and incentives that scale up and down with commodity prices.

The only problem with this system, Gee noted in his report, is that it assumes that when royalty payments go down, making Alberta more competitive, that other costs don’t increase to compensate.

“I thought it might be interesting to look at all other taxes, fees and levies we are charged to see if the various governments are really collecting less, which is truly allowing us to be more competitive in the North American market, or maybe collecting the same, just in different form,” Gee stated.

Looking specifically at Peyto’s operating costs and what the company pays

for Alberta Energy Regulator fees, municipal property taxes, municipal activity fees compared to royalties, “we see that the reduced royalty benefit is not quite as good as we think.

“Yes, there are much lower royalties when gas prices are low, but that savings is partially offset by increased taxes and fees in other parts of our business. The total government take is not as tied to commodity prices as one initially thinks, with closer to 20 per cent now being fixed fees.”

Considering that the margins that enable the average Canadian gas producer to be competitive in a North American marketplace are already thin, Gee stated, “Increases in other forms of take, which are not tied to the commodity price, may be enough to tip the scales in favour of other jurisdictions, like the Marcellus or Eagle Ford.”

G ee a rg ued t hat it ’s somet h i ng Canadian governments at all levels need to keep in mind.

“Perhaps it’s not such a big deal for Peyto, who enjoys a significant cost advantage over the industry, but it could be a deal breaker for those that don’t.”

Tourmaline continues growing

By Paul Wells

Tourmaline Oil Corp. achieved record quarterly production and funds f low from operations as increased output from new wells and acquisitions coupled with strong natural gas prices to boost results.

“For Tourmaline, our fi rst quarter was a record in all regards,” president and chief executive officer Mike Rose told a firstquarter conference call.

Production for the three months ended March 31, 2014, averaged 102,563 barrels equivalent per day—a 49 per cent increase over the average production for the same quarter of 2013 of 68,636 barrels equivalent per day.

Output was 85 per cent natural gas weighted in the fi rst quarter of 2014, compared to 89 per cent during the comparable period last year.

“We had record oil and liquids production of approximately 15,000 barrels per 24

J U LY 2 0 1 4 • O I L & G A S I N Q U I R E R

day, or 15 per cent of total corporate production,” Rose said. “Overall liquid production has been steadily increasing on a proportionate basis.”

The accelerated growth in oil and natural gas liquids production is the result of increased drilling in the Spirit River/Peace River High Charlie Lake oil plays, the additional incremental liquids recovered in the Wild River area via deep-cut processing, which began in late 2013, and stronger-thananticipated condensate recoveries from new wells tied in in northeastern British Columbia.

Current output is in the range of 115,000–120,000 barrels equivalent per day, which Rose noted was up substantially from the first-quarter average.

“We have an additional 16,000 barrels equivalent a day that are actually tied into facilities, and they’re awaiting facility expansions to come on stream,” Rose said.

“In addition, we have 10,000 barrels equivalent a day that’s drilled and tested and behind pipe but not t ied in yet. We’ll get after that right after spring breakup and bring that production on primarily during the third quarter. Things are going extremely well on the production front.”

Full-year average production guidance for 2014 remains unchanged at 120,000 barrels equivalent per day.

First-quar ter capital spending of $466.4 million was $75 million higher than originally forecast, largely due to the addition of a 17th drilling rig with associated completion spread; participation in five unbudgeted third-party-operated Deep Basin horizontals; and as significant participation at Crown land sales in the Alberta Deep Basin and in northeastern British Columbia.

Central Alberta

“ We have an additional 16,000 barrels equivalent a day that are actually tied into facilities, and they’re awaiting facility expansions to come on stream.”

— Mike Rose, president and chief executive officer, Tourmaline Oil Corp.

In addition, upfront expenditures related to facility expansions scheduled to come on stream in the second half of 2014 increased capital investment.

Expenditures on exploration and production were $461.3 million, compared to $262.7 million for the same quarter of 2013, which is consistent with the company’s aggressive growth strategy.

The increase in drilling and completion costs reflects the higher rig count from 10 drilling rigs in the fi rst quarter of 2013 to 17 drilling rigs in the first quarter of 2014.

Rose said that 20 of 21 first-quarter Deep Basin horizontals with 30 days of production history have a 30-day initial

production rate of 10.2 million cubic feet per day, compared to the current company template forecast of five million cubic feet per day. Tourmaline drilled 34 gas wells, six oil wells and no dry holes in the quarter.

“We’re increasing our rig fleet to 18 post breakup. We currently have three rigs working right now—two in B.C. and one on the Peace River High Charlie Lake horizontal play. We expect all 18 rigs to be working at some point in June,” Rose said.

He added that the company’s Lower Montney and Charlie Lake programs continue to impress.

“In northeast B.C., company-interest production has reached the 30,000-barrels-

equivalent-per-day level. We have drilled two successful follow-ups to our new condensate-rich Lower Montney discovery, which we are very encouraged by. And the extra rig that we’ve added, the 18th rig, will be focused on this new play,” Rose said.

“On the Charlie Lake play, we’ve now drilled 75 successful Charlie Lake horizontals and no dry holes. Most importantly, our sour gas injection plant at Spirit River that we’re building remains on schedule for an October start-up. That will immediately lead to a fairly large production bump as we do have significant shut-in production there.”

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25

Central Alberta

Penn West aims for 200 Cardium wells per year

By Pat Roche

Before David Roberts took over as president and chief executive officer of Penn West Petroleum Ltd., the company had a planned annual spending of $50 million on its Cardium play.

Roberts, who took the helm a year ago, doubled spending in the central Alberta light oil play to $100 million.

This year, he doubled the Cardium budget again to more than $200 million, and he plans to increase it to between $400 million and $500 million in 2015.

With a typical Cardium well costing more than $3 million, and with drilling to ramp up to 200 wells per year, Penn West will eventually spend more than $600 million per year in the Cardium.

To put that into perspective, the company’s overall 2014 capital budget is $900 million, unchanged from last year.

Penn West plans to increase its Cardium production to 60,000 barrels equivalent per day by 2018, up from 25,000 barrels per day at present.

Many tight oil players are stymied by sky-high production decline rates that force them to devote a large share of their capital budgets to offsetting the previous year’s declines, leaving little to spare for growth.

But Roberts says Penn West’s legacy production gives it a huge advantage. (The company reported average first-quarter output of 110,795 barrels equivalent per day.)

Penn West’s overall production decline rate, like the decline rate in its Cardium play, is only 20–22 per cent, Roberts said.

That’s despite first-year declines of roughly 50–70 per cent on Penn West’s multi-frac horizontal Cardium wells.

“I think one of the unique things about Penn West is we’re probably the only company that has running room enough to actually drill those wells on a continuous basis and offset that decline,” Roberts said.

He believes the company can lower its overall Cardium decline rate even further with increased waterflooding.

“We are pursuing integrated development—that is, installing pressure maintenance sooner in our programs to preserve recoveries and, importantly, leading to lower declines on a regional, and eventually, corporate level,” he told shareholders.

“But we also have the well stock...to be able to offset those declines [on new wells], and hence my comments that we can grow production from 25,000 barrels a day to 60,000 over the next four years,” Roberts said.

“We’re fortunate that the original operators in the Cardium put in waterfloods back in the 1960s to support the pressure in the field,” he said. “We are chasing a contingent resource target of over 600 million barrels of oil equivalent, of which 500 million barrels is light oil, with a drilling inventory that may reach 2,500 locations.”

If Penn West drills 200 wells per year on its core Cardium acreage, it will still have more than 10 years of drilling locations in the play, Roberts said.

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J U LY 2 0 1 4 • O I L & G A S I N Q U I R E R

SOUTHERN ALBERTA WELL ACTIVITY MAY/13

MAY/14

Wells licensed

62



MAY/13

MAY/14

Wells spudded

18



MAY/13

MAY/14

11



Rigs released

▼

▲

Source: Daily Oil Bulletin

S.A.B. Southern Alberta

Legacy pushing waterfloods at Turner Valley

By Pat Roche

Photo: Joey Podlubny

Although the company hasn’t yet booked any waterflood reserves, Legacy Oil + Gas Inc. believes the secondary recovery method has the potential to double its reserve base.

Using Sproule Associates Limited’s contingent resource estimate and an assumed recovery factor of 10.5 per cent, Legacy believes it could add reserves of about 114 million barrels of light oil through waterflooding—roughly doubling its existing reserve base, said president and chief executive officer Trent Yanko.

“This is incremental to what we have booked today. We don’t have any waterflood barrels booked today. We just have a little bit of enhanced performance from a couple of wells,” Yanko told the company’s annual meeting.

R e f e r r i n g t o L e g a c y ’s l a n d i n Saskatchewan and Manitoba, he said: “If

we get a 10.5 per cent incremental recovery factor, it’s about 114 million barrels. Our corporate reserves are in and around that number. So we have the potential to double our reserves through the waterflood.”

The light oil producer has two main areas. One is the Williston Basin of southeastern Saskatchewan, Manitoba and North Dakota, accounting for about 70 per cent of its production. The other is the Turner Valley area of Alberta, which makes up about 30 per cent of its output.

“In all the areas, including Turner Valley, which is a conventional asset, we’re pursuing waterflooding. We’ll continue to ramp that up,” Yanko told shareholders.

Legacy drills only horizontal wells and about three-quarters receive multiple-stage hydraulic fracture treatments, he said.

Multi-frac horizontal wells have high initial

Legacy believes it could add 114 million barrels of reserves through waterfloods at its Turner Valley and Williston Basin properties.

production decline rates, which several tight oil producers are trying to mitigate by waterflooding.

“We do focus on waterflooding because, fi rst and foremost, by putting water back into the reservoir, you maintain the pressure. The longer you can maintain the pressure, the more oil you produce. And a simple rule of thumb in a lot of the reservoirs we’re in, it’s basically a doubling of the recovery,” Yanko said.

He added that waterflooding also helps tight oil and tight gas producers sustain long-term production growth.

“That reduction of your decline rate adds to your sustainability—you need to spend less money to stand still,” Yanko said. He acknowledged high decline rates are “kind of the Achilles heel of a lot of the multistage frac horizontal plays. As an industry, we’re seeing higher and higher decline rates than we’ve ever seen in history on these plays. So it gets a lot tougher to grow.”

He said Legacy’s waterflood strategy “allows us to be much more sustainable in the future than most of our peers. So that is a big differentiating factor.

“And it’s a source of free cash flow. In a typical waterflood, if the base decline is five or six per cent—versus a multistage frac horizontal well that could be 30 or 40 per cent—your sustaining capital is less, and therefore your free cash flow is more,” he added. “A typical waterflood would have free cash flow of 90 per cent. So if you had $100 million of cash flow coming from an asset, $90 million of that is free cash flow. It doesn’t take a lot to maintain production.”

Yanko said Legacy has been “actively pursuing waterflood since 2011. We had a strategy in mind when we started [the company] in 2009. We have a number of pilot projects. We expanded those pilots. We’ve done the waterf lood simulation work.

We’ve done the modelling. We’ve got the pilot projects going.”

O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

27

Southern Alberta

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Hemisphere to drill up to an additional 10 wells Hemisphere Energy Corporation is expanding its capital expenditure plans for the remainder of 2014, as a result of its recently closed $10-million financing.

Hemisphere plans to drill up to 10 additional wells in the remainder of 2014, bringing the total for the year up to 13 wells. The company will also optimize, workover and recomplete a number of existing wells, acquire 3-D seismic to assist in defining future drilling locations and continue to build its land holdings with growth potential.

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Wit h t he positive results of Hemisphere’s fi rst Atlee Buffalo horizontal well achieving a 90-day production rate of approximately 90 barrels per day (93 per cent oil), the company will focus on further development in the Atlee Buffalo area.

Hemisphere anticipates a five-well summer drilling program to begin the fi rst week of June. Another five wells are scheduled as part of a follow-up fall drilling program.

The increase in the 2014 capital budget is mainly devoted to additional drilling in order to add significant production, reserves and cash flow. The budget will be fi nanced using cash flow from operations and the company’s existing credit facility of $10.5 million, which is currently undrawn.

— DAILY OIL BULLETIN

28

J U LY 2 0 1 4 • O I L & G A S I N Q U I R E R

S.K.

SASKATCHEWAN WELL ACTIVITY MAY/13

MAY/14

Wells licensed

25



MAY/13

MAY/14

Wells spudded

62



MAY/13

MAY/14

3



Rigs released

▲

▲

Saskatchewan

▲

Source: Daily Oil Bulletin

Crescent Point reports strong first quarter

By Paul Wells

Photo: Joey Podlubny

Crescent Point Energy Corp. delivered record quarterly production in the first quarter and has revised its 2014 guidance upward.

In early May, president and chief executive officer Scott Saxberg told a fi rstquarter conference call that the company continued to implement its dual-track growth plan of advancing its cemented liner completions technology and expanding its waterflood programs in order to lessen corporate declines and increase ultimate reserve recoveries.

“We’ve always believed that small improvements in technology lead to big outcomes when applied to a large drilling inventory, and we’re seeing the benefits of that strategy as we continue to hit new records,” he said.

Saxberg said the company’s waterflood programs continue to deliver as promised and remain an integral component of Crescent Point’s operations going forward.

“To put it in perspective, the waterflood program as it is today—at 15,000

barrels—is the third largest in western Canada already. And in the next couple of years, it will compete with the fi rst- and second-largest waterf loods in western Canada,” he said.

Based on the company’s performance to date, it is increasing 2014 guidance for production. The company’s average daily production in 2014 is expected to increase to 134,000 barrels equivalent per day from 133,000 barrels per day.

Capital expenditures for the year remain unchanged at $1.78 billion. During the first quarter, the company spent $415.7 million on drilling and development activities, drilling 214 (173.6 net) oil wells with a 100 per cent success rate.

First-quarter drilling activity followed up on the hectic pace the company set in 2013.

“For the first time in our company’s history, in fi rst quarter we were recognized within the industry for having drilled the most metres in western Canada in a quarter,” Saxberg said. “By the end of this

Crescent Point spent $416 million in the first quarter drilling 214 gross oil wells.

year, we will have drilled and fracture stimulated more than 2,700 multistage horizontal wells as a company. That level of experience provides a significant technical advantage for us, which we are always looking to leverage across our asset base.”

Drilling and development expenditures in the fi rst quarter were approximately 10 per cent under budget, while production levels in the quarter were approximately fi ve per cent over budget. Crescent Point also spent $154.7 million on land, seismic and facilities, for total development capital expenditures of $570.4 million.

In the first quarter, Crescent Point continued to successfully execute its large capital program in southeastern Saskatchewan and Manitoba. Successful results in the company’s Viewfield Bakken and Flat Lake resource plays in southeastern Saskatchewan continue to be strong drivers of Crescent Point’s organic production growth.

“We are especially excited about our Flat Lake Torquay discovery that is fast becoming another large-scale resource play success for the province of Saskatchewan,” chief operating officer Neil Smith said.

“We combined our proprietary geological learnings from our North Dakota Three Forks play with our knowledge of southern Saskatchewan to unlock this formation’s resource potential. In less than 12 months, we have grown production to approximately 5,100 barrels equivalent per day.”

Crescent Point has identified more than 480 low-risk Torquay drilling locations on its lands, including the CanEra Energy Corp. assets acquired in April. With more than 880 net sections of land with Torquay potential—of which 280 net sections are in the company’s core Flat Lake area— Crescent Point believes there is significant potential upside in the play.

“The Torquay is a great addition to our portfolio of high-quality resource plays,” Saxberg said. “It is at an early stage of O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

29

Saskatchewan

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— Scott Saxberg, president and chief executive officer, Crescent Point Energy Corp.

delineation, and we are excited about the potential scale and economics of the play.”

Crescent Point’s plans for the Torquay play at Flat Lake in 2014 include the drilling of approximately 45 net wells—11 (10.6 net) of which were oil wells drilled in first quarter—and initiating construction of a gas plant that is expected to be operational in 2015.

The company also recently commissioned a new battery in the Flat Lake area to accommodate increasing production volumes.

During the fi rst quarter, Crescent Point drilled 78 (72.9 net) oil wells in the Viewfield Bakken resource play. The company continues to refi ne its one-mile, 25-stage cemented liner completion technique and its waterflood program in the play, which are both driving strong rates of return.

The company has grown volumes that are positively affected by waterfloods to more than 15,000 barrels per day, and plans to double both the number of water injection wells and the volumes affected by waterfloods in the play over the next two years.

To put the company’s significant waterflood program into perspective, the two largest pools in western Canada, the Weyburn Midale pool and the Pembina Cardium pool, are producing approximately 30,000 barrels per day and 60,000 barrels per day, respectively.

Also during the first quarter, the company drilled 27 (13.7 net) oil wells in other areas of southeastern Saskatchewan.

Crescent Point continued to expand its waterflood program in the Lower Shaunavon resource play during the fi rst quarter. In total, Crescent Point currently has 21 water injection wells operating in the Lower Shaunavon zone.

In 2014, the company plans to double the amount of water injection wells operating in the play, to apply for approval of its second Shaunavon unit and to expand its Upper Shaunavon waterflood pilot. Based on results to date, the company estimates it has reduced decline rates by up to 10 per cent in waterflood-affected areas compared to areas not under waterflood.

During the fi rst quarter, Crescent Point drilled 41 (40 net) oil wells in Shaunavon and has 142 net oil wells planned for 2014.

As the company continues with the largest Shaunavon drilling program in its history, it will continue to refi ne its cemented liner completion technology.

Crescent Point believes that using 25-stage cemented liner completions should ultimately lead to positive technical reserve additions on its remaining booked drilling inventory and existing producing wells in the future.

In 2014, the company also plans to drill 90 net wells from pad locations that allow Crescent Point to drill up to three net wells per pad location, as opposed to one net well. The drilling of more wells from these pad locations should result in capital expenditure savings through cost optimizations.

Saskatchewan

Viking oil producer Raging River boosts budget

By Pat Roche

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ISO 9001 :2008 REGISTERED FIRM

Viking oil driller Raging River Exploration Inc. more than tripled its profit and doubled its cash flow and production in the first quarter.

Citing production and commodity price strength, the company has increased its 2014 capital budget by $10 million to $245 million.

Raging River—which is focused solely on Viking light oil in the Dodsland area of southwestern Saskatchewan—reported record fi rst-quarter production of 9,805 barrels per day (96 per cent oil), an increase of 26 per cent from the fourth quarter of 2013.

The company has increased its average 2014 production guidance to 9,800 barrels per day from 9,500 barrels, and increased exit guidance by about three per cent to 12,100 barrels per day.

Daily Oil Bulletin records show the company rig released 167 wells as operator last year. When non-operated wells are included, Raging River has drilled about 400 wells over the past 24 months, said president and chief executive officer Neil Roszell.

Average well costs are between $875,000 and $925,000 and cycle times are about 20 days per well, Roszell told the company’s annual meeting. He said the company has 280 net sections of land—235 of which have been targeted specifically to be within the Viking light oil fairway in the oil area.

Of the 235 Viking sections, probably somewhere around 215 will have economic oil on them and about 20 sections at some point

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Raging River first-quarter Viking production

will drop off, Roszell said. “We’re not scared to drill dry holes....

That will happen over time, and that number will move around.”

He said the company plans to drill roughly another 170 wells during the rest of 2014.

Roszell said Raging River’s corporate decline rate is currently 38 per cent, but he expects it to level off in 2016, and then fall by about three per cent per year.

Seventy wells have been on stream for at least 60 days with average oil rates of 51 barrels per day. The company said the averages include 25 wells that were drilled on previously untested sections.

Raging River said this is equivalent to the average results of all 250 wells it drilled between March 2012 and December 2013.

Gibson Energy is a growth-oriented, solutions-based, North American midstream energy service company with an integrated portfolio of businesses.

O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

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Equipment [L.P.] group maintained its market share in the specialized transportation field.”

Mullen’s 13 other oilfield services entities—which are generally tied to drilling activity in western Canada—were flat in 2013.

“The first quarter of this year looks similar to the last,” Mullen said.

Consolidated revenue in the first quarter for Mullen’s oilfield services companies increased by $15 million, or 5.8 per cent, to $272.6 million as compared to $257.6 million in the same period one year earlier, primarily due to increased demand for fluid hauling and related production services, as well as an increase in revenue generated by large-diameter pipeline construction projects.

Mullen said the revenue growth came despite a “slow-growth economic environment and the lack of any real growth in drilling activity in western Canada.”

Premay Pipeline Hauling, Heavy Crude Hauling L.P. and E-Can Oilfield Services L.P. were the main drivers of the revenue growth, like in 2013, he added.

While the market remains flat, Mullen said he is still optimistic about the future for the oilfield hauling sector for a number of reasons.

“First, energy in the form of natural gas or crude oil is a consumable, which means the oil and natural gas industry must continue to pursue the next molecule for future consumption.

Photo: Anatoliy Kosolapov/Thinkstock.com

W

estern Canada’s oilfield haulers have been in a holding pattern for the last two years as flat drilling expenditures have meant little room for growth, says Murray Mullen, chief executive officer of the diversified trucking and oilfield service company Mullen Group Ltd. “Our oilfield services segment is essentially a derivative of the annual spending by the oil and natural gas sector in western Canada, which includes expenditures for activities such as drilling activity, oilsands development, infrastructure investment and ongoing servicing and maintenance,” Mullen told shareholders in his annual address in May. “2013 was in many respects very similar to the overall economy, characterized by little growth and an extremely competitive marketplace.”

With Mullen Group’s array of oilfield hauling services, however, there were some bright spots.

“Pipeline-related activity was robust as the large mainline pipeline carriers rushed to build new pipelines to handle the increasing flow of crude oil produced in western Canada,” said Mullen. “Premay Pipeline Hauling [L.P.] had a very strong year hauling, stockpiling and stringing pipe for the mainline big-inch pipe contractors and pipe companies. In addition, our Premay

Cover Feature

BIG

WHEELS

TURNING Oilfield haulers track ups and downs in industry capital spending, while awaiting gas drilling uptick

By Darrell Stonehouse

All economies need energy,” he said. “Second, North America is resource rich, an advantage that not all countries are afforded.

Western Canada happens to be blessed with some of the very best prospects in North America and is our primary base of business.

That’s an attractive combination—ongoing demand accompanied by opportunity in a market we know, understand and in which we already have a large presence. But the energy story is a complicated one and subject to cyclical ebbs and flows, highs and lows. It can also be extremely competitive, especially following a cyclical high. Demand levels and pricing can decline very quickly, challenging even the best operators.”

He said that until new export pipelines are built, he expects slow growth in the oilfield transportation sector.

“As the U.S. embarks on a full-court press toward energy self-sufficiency, Canadians must realize that there are two obvious outcomes. First, the U.S. will not need as much of our oil or natural gas. As their production grows, they will import less from Canada,” he said. “Second, and of equal importance, is the potential for the U.S.—once our biggest and only outside consumer of these commodities—to be our biggest competitor. Under this dual threat, we must build pipelines and infrastructure that will allow oil and gas companies access to new overseas markets.

We need pipelines for both commodities if Canada is to maintain its economic standing, create good jobs and have the tax revenues so badly needed. We need new pipelines. It’s that simple.”

There are signs, on the natural gas side, of a ramp-up in drilling in anticipation of liquefied natural gas (LNG) exports.

During the winter drilling season, around 100 rigs were active in the Montney play straddling the border of Alberta and British Columbia. Progress Energy Canada Ltd., the busiest operator in the Montney, reported it was halfway to proving up the 14 trillion cubic feet needed to supply its parent company PETRONAS’ proposed LNG facility.

Drilling is also ramping up in the condensate-rich sections of the Duvernay in Alberta. Around 200 wells are expected in the Duvernay this year, with as many as 500 expected when full development starts.

The development in these plays will have a huge impact on the oilfield hauling sector. The extended-reach horizontal wells and multistage fracs being used in the Montney and Duvernay are an order of magnitude larger than what is being used to develop the tight oil plays that have driven oil and gas investment the last five years, meaning much more equipment and materials must be trucked to site.

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Cover Feature

Gas drilling means bigger fracs and more materials Play Bakken

Fracture (stages/well)

Fracturing HHP required

Frac size (tonnes/stage)

10.0–25

2,000–4,000

6.0–12

Montney

10.0–20

18,000–40,000

50–250

Duvernay

10.0–20

35,000–50,000

80–150

Sources: Canyon Technical Services Ltd.; Calfrac Well Services Ltd.

Here is an example. In the Bakken tight oil play in southeastern Saskatchewan, the average frac size is six to 12 tonnes of proppant per stage. In the Montney, the average frac size is between 50 and 250 tonnes per stage. In the Duvernay, the range is 80–150 tonnes per stage.

The gas wells are also significantly longer with an average total depth of 3,500 metres, compared to 2,000 metres for oil wells.

This translates into a lot of truckloads of materials. A 2010 study by ALL Consulting for Marcellus shale play in New York State in the United States shows the effects the large shale gas plays have on oilfield hauling. The study required around 1,150 one-way loaded truck trips to drill and complete the average Marcellus well in early development. Once development drilling, water pipelines and recycling begin, that number drops to a still impressive 650 trips per well.

Truckers have already seen a significant increase in work since multistage fracking took off in 2007, hauling frac sand and other proppants. According to the Freedonia Group, Inc., a U.S. market

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research provider, Canadian proppant demand grew from 1.69 billion pounds in 2007 to 5.84 billion pounds in 2012 (annual growth of 28.1 per cent). It is expected to more than double to 12.45 billion pounds in 2017.

Like in other sectors of the oilfield, worker shortages could make adjusting to this potential transportation boom a challenge.

Mullen said the challenge of replacing older workers with younger ones is widespread across the sector but is particularly acute for long-haul drivers.

“This is a well-known trend, but it is my premise that we are actually nearing a critical stage when age becomes a real issue,” he said. “Quite simply, this part of the industry is unable to attract young drivers. As such, it is only a matter of a few years before this issue has a real impact. Any market that has demand growth accompanied by supply restraint can expect pricing leverage. I continue to hold onto this belief that the day will come when pricing leverage returns to the trucking/logistics sector. Until then, we must remain competitive and accept margins that are below our expectations.”

Feature

Operators in west-central Alberta are in development mode in Cardium and NGL plays, while chasing new opportunities

Photo: Joey Podlubny

I

By Darrell Stonehouse

t’s been over 60 years since Mobil Oil Corporation, now Exxon Mobil Corporation, drilled into the Cardium Formation and discovered the Pembina oilfield in west-central Alberta in 1953, but with the advent of horizontal drilling and multistage fracturing, the field still has lots of life left in it.

Explorers have expanded the reach of the Cardium outside the Pembina core area, turning the play into Alberta’s premier tight oil development, with production over 75,000 barrels per day from horizontal wells in 2013. Money is expected to pour into the Cardium in 2014 and beyond.

Penn West Petroleum Ltd. expects its development capital spending on the Cardium to climb to $800 million per year by 2018.

“Clearly, the Cardium is the heart of the company, and we envision increased capital spending in the play, reaching $800 million invested per year there within five years,” president and chief executive officer David Roberts told a conference call announcing the company’s 2014 spending plans.

To put the $800-million figure in perspective, Penn West’s entire 2014 exploration and development capital spending is expected to be $900 million, of which $269 million is earmarked for the Cardium.

Roberts said Penn West’s Cardium well costs and cycle times are improving, and it is posting solid recoveries per well on primary production. Historically, the Cardium has been waterflooded successfully using vertical wells, and now “proven results from the use of horizontals are leading to further recovery improvement,” he added.

Penn West is the leading landholder in the Cardium with 600,000 net acres.

“This would be a feature play in any portfolio,” Roberts said of the Cardium. “We have hundreds of well opportunities at 30-plus per cent rates of return at moderate price assumptions. The Cardium is indeed a company maker.”

Vermilion Energy Inc. shares this optimism about the play, after reporting strong results in 2013.

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Feature

Donadeo said that Vermilion continues to review a significant inventory of more than 120 additional locations that may become economic as the company expands the use of extended-reach horizontal wells (greater than one mile in length) and further optimizes completion technology and well design.

“We have also initiated a water injection pilot to test applicability of waterflooding to this reservoir as a means to increase potential recoveries,” Donadeo said.

Bellatrix Exploration Ltd. is also spending a heavy amount of money on its Cardium land base. The company, which recently took over Angle Energy Inc. and tapped into a major investment partnership, expects to drill 115 gross Cardium oil wells in 2014.

Bellatrix has developed an inventory of 742 net remaining Cardium locations.

CARDIUM 2013 HORIZONTAL OIL WELL PRODUCTION 14,000

12,000

OIL (BBL/D)

10,000

74,802

8,000

TOTAL OIL (BBL/D)

6,000

Liquids drive more drilling

4,000

Anderson Energy

Imperial Oil

ConocoPhillips

ExxonMobil

Angle Energy*

Bonavista Energy

Baccalieu Energy

Bellatrix Exploration

TORC Oil & Gas

Manitok Energy

Pengrowth

Penn West Exploration

ARC Resources

Whitecap Resources

Bonterra Energy

Sinopec Daylight

Vermilion Energy

0

Lightstream Resources

2,000

OPERATED WELLS

0

50

100

1,941

150

TOTAL OPERATED WELLS

200

250

300 *Acquired by Bellatrix Exploration Ltd.

Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR

“We remained focused on the continued development of our successful Cardium light oil play, growing related production to more than 9,300 barrels equivalent per day in the fourth quarter,” chief executive officer Lorenzo Donadeo told the company’s year-end 2013 conference call. “We have considerable inventory to progress the play toward targeted production levels of 12,000– 14,000 barrels equivalent per day over the next few years.”

Cardium well performance remains predictable, reflective of the high-quality, consistent nature of the reservoir underlying the company’s land position in the West Pembina region, he said.

Since entering the play in 2009, Vermilion has brought a total of 223 (158.9 net) Cardium wells online. This year, the company expects to drill 30 net wells. Entering 2014, the company has an inventory of nearly 200 net economic one-mile-equivalent wells remaining to be drilled.

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Outside the Cardium, gas plays with high liquids content are catching attention in west-central Alberta.

Bonavista Energy Corporation is targeting liquids-rich gas in the Glauconite and Ellerslie formations.

The Glauconite Formation will be the major source of growth in the next couple of years, with spending of $150 million to $200 million per year in 2014 and 2015 and an anticipated doubling of production by the second half of 2015, from the current 17,000 barrels per day, according to company president and chief executive officer Jason Skehar.

This year, plans call for spending of $161 million to drill 58 (gross) Glauconite wells where Bonavista has 400 horizontal locations and has already drilled 186 horizontal wells.

Bonavista has also budgeted $44 million to drill 11 gross wells in the liquids-rich (90 barrels per million cubic feet) Ellerslie, which Skehar describes as the “most undervalued, probably unappreciated play in the company.”

It only recently began drilling horizontal Ellerslie wells after drilling vertical wells for a decade, and “we had some tremendous results in 2013,” he says. Bonavista drilled five horizontal wells in the latter part of the year. “If we continue on with that success rate in 2014, I am convinced that the Ellerslie will overtake the Glauconite in terms of capital allocation within the next couple of years.”

Over the past five years, Bonavista has increased its landholdings in two core areas, west-central Alberta and the Deep Basin of Alberta, by 160 per cent to 2.13 million acres in 2013, from 815,000 acres in 2009. Approximately 70–80 per cent of its current production and reserves exist in those two core areas. The company has a drilling inventory of 1,650 locations, of which 1,465 (89 per cent) are horizontal wells and 80 per cent are in the two core areas.

Both Vermilion and Bellatrix are also developing liquids-rich gas in west-central Alberta along with their Cardium tight oil plays.

In 2013, Vermilion drilled 3.7 net wells targeting Mannville liquids-rich gas in the West Pembina area. Drilling results to date have exceeded initial expectations, Donadeo said.

Average production rates per well over the first six months have come in at 2.4 million cubic feet per day of sales gas and 310 barrels per day of liquids—of which 80 per cent is condensate.

In 2014, Vermilion plans on drilling 5.7 net Mannville wells, and expects drilling activity to increase in future years as it continues to develop the play and expand its inventory of prospects. It has 318 net sections of Mannville rights, with 37 drilling locations identified and 50 prospective drilling locations.

Feature

GLJ PETROLEUM CONSULTANTS LTD. ALBERTA NATURAL GAS LIQUIDS PRICE FORECAST

ACTIVE SOUTH DUVERNAY LANDHOLDERS WELLS DRILLED

120

ACREAGE (NET SECTIONS) 0

Edmonton Pentanes Plus

100

200

300

400

500

600

700

Encana Corporation/PetroChina Company Limited*

100

Shell Canada Limited Edmonton Butane

80

Talisman Energy Inc.

C$/bbl

Sinopec Daylight Energy Ltd. Edmonton Propane

60

ConocoPhillips Company Vermilion Energy Inc.

40

Enerplus Corp.

Spec Ethane

20

Bonavista Energy Corporation Canadian Natural Resources Limited

0 2012

2013

2014

2015

2016

2017

2018

2019

2020

Note: Effective January 1, 2014

Bellatrix is approaching its Pembina acreage as a stacked resource play similar to the Deep Basin. Aside from targeting Cardium tight oil, it is also focusing on eight other formations.

In the Lower Mannville, it has identified 100 net drilling locations and has already drilled 31 Ellerslie wells. Wells are producing around 200 barrels of liquids per million cubic feet of gas.

South Duvernay showing strong liquids shows Both Vermilion and Bellatrix also have significant South Duvernay acreage in west-central Alberta.

Donadeo said that Vermilion is appraising its position in the Duvernay, where the company has amassed 317 net sections at the relatively low cost of approximately $76 million ($375 per acre).

“Our position comprises three largely contiguous blocks in the Edson, Drayton Valley and Niton areas. To date, we have drilled three vertical stratigraphic test wells and are currently drilling our first horizontal well,” he said.

“The first horizontal test is in the downdip part of our Edson block, where condensate yields are expected to be lower than the average in our overall land position. We selected this location because of its proximity to one of our vertical stratigraphic test wells, allowing us to conduct microseismic monitoring while we frac the horizontal well after breakup.”

The company anticipates that the horizontal well production results and fracture geometries from the microseismic data will assist it in optimizing completions on future horizontal wells.

“We are confident we will be able to project the results to higher-condensate-yield drilling locations as we move to the northeast in our acreage position, which encompasses the entire breadth of the condensate-rich window,” Donadeo said.

“Our Duvernay rights generally underlie our Cardium oil and Mannville condensate-rich gas rights, which creates the potential for infrastructure, operational and timing advantages if we progress to full development of the Duvernay resource play,” he added.

*Total acreage in both North and South Duvernay.

Sources: BMO Capital Markets; Keyera Corp.; JuneWarren-Nickles Energy Group

Talisman Energy Inc. says that early results in the Duvernay are encouraging, and the company will continue to seek a jointventure partner in an effort to accelerate the pace of developing the play.

“We will figure out ways to reduce the cost of drilling these wells and improve overall production rates, but I think the very positive outcome of the work we have done so far is we have confirmed that we are in some very attractive acreage in the south,” president and chief executive officer Hal Kvisle told the company’s fourth-quarter conference call. “We have got some good spots in the north, and some parts of our northern acreage are gas focused, and we are currently appraising some of that gas acreage with a view to running it through our capacity at the deep-cut plant and recovering significant natural gas liquids from that,” he added. “So, I think the key theme of our Duvernay position is one of liquids—very significant amounts of condensate in the southern part and significant amounts of natural gas liquids in the northern part, as well as one block we called Waskahegan, which is particularly attractive in the north and surrounded by some pretty attractive wells drilled by our competitors.”

The company currently holds interests in 347,000 net acres of land in the Duvernay. Talisman has drilled eight appraisal wells to date in the play and continues to evaluate its extensive acreage position.

The two most recent wells drilled in the South Duvernay had seven-day average rates of 2.2 million cubic feet per day of gas and 550 barrels per day of condensate.

Although these are early stage results, Kvisle said they show the promise of Talisman’s Duvernay assets in the southern portion of the play.

“The two wells that we announced are in the southern part of our Duvernay position and...we are quite excited by the liquids potential, and one of the purposes of releasing this information O I L & G A S I N Q U I R E R • J U LY 2 0 1 4

37

Feature

was to indicate that we are in a significantly liquids-rich part of the Duvernay,” he said.

This year, the company plans to drill six wells as it continues to appraise its extensive land position. Talisman will drill its first multi-well pad in the southern part of the play and will begin a process to secure a strategic partner.

Emerging shale plays could be game changers The South Duvernay is the furthest along of central Alberta’s shale plays, but it isn’t the only show in town.

A number of explorers have been testing the Second White Specks shale, including Yangarra Resources Ltd. Yangarra has been very keen on shale plays and has done a lot of work on the Second White Specks Formation in the oil window, accumulating 45 (29 net) sections of land, says company president and chief executive officer James Evaskevich.

However, the company is finding that “it is not easy to crack the nut on this particular play,”—thick shale lying below the Cardium and just above the Viking. “We think we are a lot closer.”

The Second White Specks has an estimated 10 million to 20 million barrels of original oil in place per section, and considerable oil has been produced over the past 30 years, he says.

With three horizontal wells and two vertical wells in the play, “we’ve drilled more of them than anybody else to our knowledge,” Evaskevich says. With the Second White Specks now generating $250,000–$300,000 per month in revenue, it is content to pay down the capital it has put into the play while seeing what other producers in the area are doing, he says.

Yangarra has one horizontal well that has six stages ready to fracture but still has to decide when to finish the job, as the well is making “an awfully good profit just the way it is.”

Yangarra believes it needs to revise its frac process and knows what it wants to try next, but “it’s pretty easy just to sit back when you are generating that much income out of there,” Evaskevich says. “We want to get closer to having the house’s money.” In the company’s view, “ultimately this is going to be a big play. It’s going to take some time.”

DeeThree Exploration Ltd. is more advanced with its Belly River oil play in central Alberta.

DeeThree has been working on developing its Belly River assets since 2011. “We basically pioneered the Belly River play.

Nobody else was drilling in the Belly River play. Today, we’ve got, I think, 338 future well locations on the whole block, and I do believe that number is going up to north of 500,” company president and chief executive officer Martin Cheyne says.

“It’s probably the biggest oil pool that I’ve ever been associated with,” he adds. “I think we’ve got somewhere between 600 million and 700 million barrels of oil in place here, and there’s only been 14 million barrels taken out.”

He believes the Brazeau Belly River pool will prove to be one of Alberta’s blockbuster conventional light oil reservoirs.

“Nobody believed us [when we said] how good this asset was,” Cheyne recalls. “And to be honest with you, the market still doesn’t realize how big this Belly River sand package is. I mean, we’re making baby steps. We’ve been on the road a lot this year.

Guys are starting to realize how good this play really is. We keep putting press releases out of 1,000-barrel-a-day-plus wells.”

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