Oil & Gas Inquirer October 2013

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Canadian industry faces challenges and opportunities as U.S. reverses decline in domestic petroleum production

Plus: Oilfield haulers in holding pattern until new export capacity comes on stream

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CONTENTS

OCTOBER.

in the news

11

Average gas well a money loser, says CERI

regional news

17

British Columbia

Pricing, pipeline construction biggest LNG export hurdles, says study

21

Northwestern Alberta

25

Northeastern Alberta

Suncor attempts to reclaim fen landscape

29

Central Alberta

Wilrich play taking off

33

Southern Alberta

Spyglass Resources output up

35

Saskatchewan

Raging River production up, capital spending to climb

Higher Peace River production drives Baytex growth

features

Cover Feature

36 Set to soar Canadian industry faces challenges and opportunities as U.S. reverses decline in domestic petroleum production

42 Waiting for the rebound Oilfield haulers in holding pattern until new export capacity comes on stream

business intelligence

45

Lack of money hurting resource play developers

every issue

8 Stats at a Glance 46 Political Cartoon Cover design: Peter Markiw Illustration: skalapendra/Photos.com

OIL & GAS INQUIRER • OCTOBER 2013

5

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Editor’s Note Vol. 25 No. 8 EDITORIAL EDITOR

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

Lynda Harrison, Carter Haydu, Deborah Jaremko, James Mahony, Pat Roche, Elsie Ross, Paul Wells

Red Square in Ottawa, not Calgary

EDITORIAL ASSISTANCE MANAGER

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

Kate Austin, Shawna Blumenschein, Tracey Comeau, Sarah Eisner, Matthew Stepanic CREATIVE PRINT, PREPRESS & PRODUCTION MANAGER

Michael Gaffney | mgaffney@junewarren-nickles.com

Hypocrisy is the art of saying one thing and then

Malaysia’s PETRONAS. PetroChina Company

CREATIVE SERVICES MANAGER

doing the opposite.

Limited has a 60 per cent stake in Athabasca

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

When it comes to attitudes toward state

Oil Corporation, while another Chinese state

Cathlene Ozubko

ownership of Canadian oil and gas assets, there

company, Sinopec Corp., owns a big chunk of

GRAPHIC DESIGNER

Peter Markiw

are politicians who are masters of the art. They

Syncrude Canada Ltd.

CREATIVE SERVICES

are called Conservatives.

CREATIVE LEAD

Christina Borowiecki, Jenna O’Flaherty, Jeremy Seeman production@junewarren-nickles.com

The evidence is readily available if one looks

With the industry starved for cash, it isn’t surprising that individual companies are taking

SALES

back over the last 40 years of Canadian history. In

funding where they can fi nd it. But it is worth

SALES MANAGER—ADVERTISING

1975, the federal New Democratic Party (NDP)

asking why there is such a dearth of domestic

introduced legislation to create a state-owned

investment in the industry. And, as usual, the

oil company to profit from the surge in oil prices

place to look is the federal government.

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

Nick Drinkwater, Tony Poblete, Diana Signorile SALES

Brian Friesen, Rhonda Helmeczi, Sammy Isawode, Mike Ivanik, Nicole Kiefuik, Gerry Mayer, David Ng, Sheri Starko For advertising inquiries please contact adrequests@junewarren-nickles.com AD TRAFFIC COORDINATOR—MAGAZINES

Lorraine Ostapovich | atc@junewarren-nickles.com

brought on by the Arab oil embargo. Pierre

The killing of the energy trusts in the

Trudeau’s Liberal Party, governing with a minor-

Halloween massacre of 2006 by Conservatives

ity, joined with the NDP. Canada’s state-owned oil

worried about a decline in tax revenues destroyed

company, Petro-Canada, was born.

a major source of funding for the industry, and an

Conservative leader Joe Clark howled in op-

engine of wealth growth for Canadians.

DIRECTORS

position to Petro-Canada’s creation. Industry,

CEO

across the board, stood against its formation. When

Safehaven.com puts it this way: “The opportunity

PRESIDENT

the Petro-Canada towers were built in downtown

to have a group of world-class companies paying

Calgary, they were dubbed “Red Square.”

taxes in Canada, and Canadians paying tax on the

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

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

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

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

Gord Lindenberg | glindenberg@junewarren-nickles.com DIRECTOR OF CONTENT

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

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

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

2nd Flr-816 55 Avenue N.E. | Calgary, Alberta T2E 6Y4 Tel: 403.209.3500 | Fax: 403.245.8666 Toll-Free: 1.800.387.2446

Edmonton

220-9303 34 Avenue N.W. | Edmonton, Alberta T6E 5W8 Tel: 780.944.9333 | Fax: 780.944.9500 Toll-Free: 1.800.563.2946

SUBSCRIPTIONS Subscription Rate

In 1990, Brian Mulroney’s Conservative govern-

Larry Cyna at the investment website

profit of these companies, has been permanently

ment finally acted. It began selling off the company,

lost. Just another example of the utter stupidity of

but it wasn’t until 2007 that it was fully divested.

politicians.”

The Conservative Party fi nally got their

The trusts, once owned by Canadians, now

way, with the private sector fi rmly in control

belong to foreigners. Here is a brief sample—Daylight

of the development of the country’s petroleum

Energy Ltd., Progress Energy, Harvest Energy and

resources. Or so it seemed.

Penn West Exploration (Peace River assets).

It now, however, appears they are fine with

All because the Conservatives, like the Liberals

state ownership of resources, as long as the state

before them, believe they know better than

isn’t Canada. The pink socialism of Trudeau was

Canadians how to spend and invest their money.

a cause for outrage, but the Red Chinese are fine.

The list of state-owned companies operating

I’ve taught my children, from when they were old enough to listen, that the government is not

in Canada continues to grow. Harvest Energy

their friend. I wish the rest of Canadians, includ-

Trust, now Harvest Operations Corp., is owned

ing the oil industry, would learn that lesson.

by the Korea National Oil Corporation. Nexen Inc. is owned by Chinese state company CNOOC Limited, Progress Energy Canada Ltd. by

In Canada, 1 year $49 plus GST, 2 years $69 plus GST Outside Canada, 1 year $99

Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com

Subscription Inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren-nickles.com GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2013 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240.

Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

N E XT I S S U E November 2013 Tackling the tight oil boom in Manitoba, plus tracking development activity in southeastern Saskatchewan.

Want to sound off on any content in Oil & Gas Inquirer?

Send your emails to dstonehouse@junewarren-nickles.com.

Please mark them as ”Letter to the Editor” if you want them published.

OIL & GAS INQUIRER • OCTOBER 2013

7

FAST NUMBERS

 billion

 billion

cubic feet per day

cubic feet per day

Current production from Marcellus shale in the northeastern United States.

Marcellus production predicted for 2020 by Wood Mackenzie Limited.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

M O NTH

OIL

GAS

Aug 2012

380

98

63

Sep 2012

447

65

12

MONTH

OIL

GAS



Aug 2012

682

148

9

67





Sep 2012

813

75

9

11



T O TA L

D RY

SERVICE

T O TA L

Oct 2012

588

80

23



Oct 2012

1,121

105

10

33

,

Nov 2012

535

137

78



Nov 2012

930

214

15

91

,

Dec 2012

483

105

51



Dec 2012

802

164

17

71

,



Jan 2013

542

87

7

9



899

161

17

83

, ,

Jan 2013

313

59

9

Feb 2013

449

124

67



Feb 2013

Mar 2013

544

149

119



Mar 2013

949

198

21

127

Apr 2013

481

91

129



Apr 2013

581

146

18

127



Jun 2013

179

14

73



Jun 2013

273

56

1

75



Jul 2013

263

59

51



Jul 2013

671

103

15

51



Aug 2013

394

46

34



Aug 2013

817

72

1

39



Wells Drilled in British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

OTHER

TOTAL

Aug 2012

53

454

Aug 2012

296

4

9

Sep 2012

11

465

Sep 2012

302

1

7



Oct 2012

28

493

Oct 2012

453

0

27



Nov 2012

78

571

Dec 2012



65

636

Jan 2013

31

31

Feb 2013

42

73

Mar 2013

66

139

Apr 2013

69

208

Jun 2013

45

330

Jul 2013

49

379

Aug 2013

26

405

*From year-to-date

8

OTHER

OCTOBER 2013 • OIL & GAS INQUIRER



Nov 2012

346

0

26

Dec 2012

282

1

34



Jan 2013

174

0

5



Feb 2013

358

0

31



Mar 2013

323

0

19



Apr 2013

88

1

5



Jun 2013

80

0

2



Jul 2013

358

1

13



Aug 2013

362

1

6



STATS

AT A

GLANCE

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, September 11, 2013 Source: Rig Locator

Alberta, September 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada Alberta

AC T I V E

OIL WELLS

Alberta

Aug 

GAS WELLS

Aug 

Aug 

Aug 

269

313



46%

Northwestern Alberta

78

108

25

51

British Columbia

50

19



72%

Northeastern Alberta

87

46

0

0

Manitoba

10

12



45%

Central Alberta

192

183

6

13

Saskatchewan

67

71



49%

Southern Alberta

37

49

15

26







%

TOTAL



386



90

WC TOTALS

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, September 11, 2013 Source: Rig Locator

Alberta, September 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada

Alberta

AC T I V E

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

Alberta

Aug 

Aug 

BITUMEN WELLS Aug 

Aug 

393

286



58%

Northwestern Alberta

0

0

7

8

British Columbia

6

18



25%

Northeastern Alberta

0

0

87

46

Manitoba

7

10



41%

Central Alberta

0

0

81

86

Saskatchewan

133

59

192

69%

Southern Alberta

2

12

0

0

WC TOTALS







%

TOTAL



12



140

OIL & GAS INQUIRER • OCTOBER 2013

9

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IN THE

NEWS Issues affecting Canada’s E&P industry

money loser

Average gas well a money loser, says CERI

By Pat Roche

The average natural gas supply cost for new production in the Western Canadian Sedimentary Basin was $4.79 per thousand cubic feet for vertical wells and $5.71 per thousand cubic feet for horizontal wells in 2012, estimated a Canadian Energy Research Institute (CERI) study.

“On average, new natural gas wells drilled in 2012 would need a higher natural gas price than current levels to be considered economic and would not recover their full costs over the producing lifetime of the well,” said CERI Study No. 136, Conventional Natural Gas Supply Costs in Western Canada.

Although its title indicates the focus is on conventional gas, the report—which divides western Canada into 52 study areas—cautioned some of these areas are “rich in tight and shale gas resources.” For

example, areas 34 in British Columbia and 14 in Alberta cover the Montney unconventional gas play. Area 42 in British Columbia covers the majority of the Horn River unconventional play.

“The area-based analysis does not specifically capture conventional versus unconventional resources. However, several single formations…are captured and analyzed based on the geological formations that attracted the top number of wells licensed in 2011,” the report said. The top licensed formations included 10 in Alberta and five in British Columbia.

The results provide an indication of the economic viability of new gas production in each of the study areas, assuming 2012 market conditions.

CERI’s supply cost estimates include all capital expenditures, operating costs,

Weighted average supply costs by region $12

$10.82 $10

$8.44

$/mcf

$8

$5.71

$6

$4.79 $3.99

$3.86

$4

$4.35

$2.10

$2

$0 Vertical

Alberta

British Columbia

Horizontal

Saskatchewan

WCSB

Source: CERI

$300,000 Average capital cost of a vertical gas well in Saskatchewan

royalties, taxes and a specified return on investment for each well. For a gas well to be economic, total revenue from gas production, less costs, has to offset the upfront capital and land costs. If supply costs are lower than the current gas price, the well is able to recover its full cost over its lifetime and make a positive return on investment. Not surprisingly, the supply cost results vary significantly across the provinces and study areas examined.

For ver t ic a l wel l s, t hose i n Saskatchewan proved the most economic at an average supply cost of $2.10 per thousand cubic feet.

While shallow gas has had a bad reputation since prices tanked, the CERI report highlighted the low capital cost of drilling shallow gas in Saskatchewan (wells between 500 and 900 metres).

Vertical wells in Saskatchewan have an average capital cost of $300,000 per well compared to more than $2 million for an average conventional well in Alberta and almost $6 million in British Columbia, the report said.

“This volume of production easily outweighs the higher capital costs of drilling in British Columbia. This high capital cost is a result of the remoteness of the resources, as the distances involved limit OIL & GAS INQUIRER • OCTOBER 2013

11

Alberta has the most attractive average supply costs for horizontal wells at $3.99 per thousand cubic feet.

access and increase the cost of services and supplies,” the report said.

CERI estimated the average supply cost of conventional vertical wells in Alberta to be the least economic at $8.44 per thousand cubic feet. This reflects the wide disparity of supply costs across the province, which range between $3.43 and an eyepopping $41.62 per thousand cubic feet, the report said.

The supply cost of $41.62 was for vertical wells in study area 3, labelled “Foothills area west of Calgary.” However, the gas supply cost of horizontal wells in the same area was only $1.38 per thousand cubic feet.

The spread of supply costs for horizontal wells between the provinces is wider than vertical wells. Alberta horizontal wells, on average, were the most attractive at an average supply cost of $3.99 per thousand cubic feet.

Despite having much lower average production rates than British Columbia, Alberta areas were still the most economic of the region due to modest capital costs.

Alberta drilling costs averaged $2.7 million per well versus $10.3 million per well in British Columbia.

A

REVOLUTION

After Alberta’s average supply cost of $3.99 per thousand cubic feet for horizontal wells, the next most attractive for horizontal drilling was British Columbia with an average of $4.35 per thousand cubic feet. Despite the significantly higher capital cost of B.C. horizontal wells, their access to significant resources and large production volumes make British Columbia attractive for drilling.

Across western Canada, capital costs account for the largest component of the supply cost, averaging 62 per cent of total costs for vertical wells and 71 per cent of total costs for horizontal wells.

T hese cost s i nc lude dr i l l i ng a nd completions, tie-in or inf rastr ucture costs, land costs, and geological and geophysic­a l costs. In addition to the well location, the well depth and the number of drilling days required are key determinants of capital costs.

Operating costs are the next biggest component, accounting for 22 per cent of total supply costs on average across the regions for vertical wells and 15 per cent for horizontal wells. Royalties and taxes make up the remaining components.

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OCTOBER 2013 • OIL & GAS INQUIRER

Photo: Joey Podlubny

In The News

cost advantage

In The News

Horizontal oil wells deliver cost advantage, says CERI study

By Lynda Harrison

The Western Canadian Sedimentary Basin’s (WCSB’s) average oil supply cost for new production was $64 per barrel for vertical wells and $40 per barrel for horizontal wells in 2012, indicating that, on average, new wells drilled last year were economic and at current oil price levels would recover their full costs over the producing lifetime of the well, said a new study, Conventional Oil Supply Costs in Western Canada, by the Canadian Energy Research Institute (CERI).

The results show that horizontal wells on average have a lower supply cost than vertical wells.

Horizontal drilling can enjoy greater economies of scale due to improved access to resources, said the study ’s author Julie Dalzell.

In addition, more areas were considered economic for horizontal wells than for vertical wells. This reflects their ability to access higher-quality resources with the horizontal drilling technique. The higher

production volumes are enough to outweigh the additional capital costs of drilling horizontally and conducting multistage hydraulic fracturing.

The analysis has been undertaken for a number of study areas and the results represent the supply cost for drilling a typical well located in each area.

The study did not look at existing oil wells, as these wells have a different economic profile given previous investment or existing infrastructure.

Supply costs for vertical wells range from $24 to $148 per barrel. The disparity ref lects the production capacity of the well and the capital costs involved with drilling.

The most economical of the vertical wells was found to be the cold bitumen production (CBP) wells in northeastern Alberta; however, drilling in this area has been limited compared with the Cold Lake area in east-central Alberta and the Slave Point Formation in central Alberta.

Both the Cold Lake and Slave Point formations are also considered attractive drilling areas.

For vertical wells, the Alberta CBP wells in the analysis averaged $1.4 million per well compared to more than $2 million for conventional wells in Alberta, and proved the most economic at an average supply cost of $31 per barrel.

This reflects their large production volumes—an average of 165,000 barrels of cumulative production—and relatively lower capital costs of the wells, said the study.

The purpose of the report is to provide an indicator of the economic viability of oil production in each of the study areas across western Canada. It analyzed drilling rig activity across western Canada and then calculated the supply cost of new wells drilled in 2012.

“It’s the first time we’ve done an allencompassing, all-oil, all–western Canada inclusive study,” Peter Howard, CERI president and chief executive officer, said.

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OIL & GAS INQUIRER • OCTOBER 2013

13

In The News

Breakdown of supply costs — horizontal $60

$47

$50

$42

$42

$40

$/bbl

$40

$34 $28

$30 $20 $10 $0 AB conventional

Taxes

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OCTOBER 2013 • OIL & GAS INQUIRER

AB CBP

Royalties

AB total

Operating costs

BC

SK

Capital costs

WCSB Source: CERI

CERI now plans to replicate the study every year or two “to give us a delta direction, whether we’re going up, down, sideways, whatever,” said Howard.

For vertical wells, Saskatchewan has the next best results, with an average supply cost of $44 per barrel.

Saskatchewan wells enjoy high-quality resources as well as relatively low-cost drilling areas with good access to services and supplies, said Dalzell.

The average supply cost of Alberta conventional vertical wells is estimated to be $82 per barrel, reflecting the lowest average production rate of all the provinces.

Vertical wells in British Columbia were the least economic, with an average supply cost of $83 per barrel. This reflects their significantly higher capital cost, with an average cost of $4.4 million per well.

The spread of supply costs for horizontal wells between the provinces is not as wide as for vertical wells. B.C. wells were the most attractive at an average supply cost of $30 per barrel, but CERI said this is based on a small number of oil wells in the province.

For horizontal wells, Saskatchewan proved the next most attractive with an average supply cost of $33 per barrel.

Saskatchewan wells enjoy the lowest capital costs of all the horizontal wells, averaging $1 million per well, due to their significantly shallower profile.

Alberta conventional and CBP wells have a slightly higher horizontal well supply cost at $42 per barrel and $47 per barrel, respectively.

The most economic areas for drilling were split across Alberta, British Columbia and Saskatchewan, said the study.

In Alberta, the Cold Lake area, the Lloydminster Formation in east-central Alberta, the Cardium Formation northwest of Calgary and the Slave Point Formation in north-central Alberta had the lowest supply costs. They were well below the average for the WCSB, ranging from $15 to $31 per barrel.

In Saskatchewan, the southwest, west-central and northwestcentral areas encompassing the Viking and Lower Shaunavon formations were also very competitive, with supply costs ranging from $23 to $34 per barrel. Even with lower production volumes compared with some Alberta areas, significantly lower capital and operating costs in Saskatchewan result in very competitive well economics for these areas.

THE OILFIELD EQUIPMENT PEOPLE.

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BRITISH COLUMBIA WELL ACTIVITY AUG/12

AUG/13

Wells licensed

58



AUG/12

AUG/13

Wells spudded

38



AUG/12

AUG/13

37



Rigs released

▲

▲

▲

Source: Daily Oil Bulletin

B.C. British Columbia

Pricing, pipeline construction biggest LNG export hurdles, says study

Photo: Joey Podlubny

High construction costs in Canada could damage the potential of liquefied natural gas coming out of British Columbia.

The commercial position of liquefaction proposals in western Canada is weakened by the need for new pipeline facilities, as well as the early stage of development of shale gas resources in western Canada, said a new report by the International Gas Union (IGU), an international non-profit organization based in Norway that promotes the use of natural gas.

Its 2013 World LNG Report included a section on the prospects and challenges for liquefied natural gas (LNG) export projects in North America. Regarding Canada specifically, the group said that based on announced costs, projects in western Canada face inexpensive liquefaction costs of roughly $1,000 per tonne, relative to projects in Australia.

However, a major factor affecting western Canadian projects is the need for a long, expensive pipeline to bring gas from northeastern British Columbia to the coast.

Currently, pipeline infrastructure in British

Columbia is limited, the report noted, with one major north-south trunk line and a smaller pipeline running west to the coast.

“As of May 2013, four projects have proposed building 500-mile pipelines” with costs of between $1,000 per million cubic feet per day and $3,000 per million cubic feet per day, which will significantly increase total project costs, the report stated.

These factors are exacerbated by the tension between Asian buyers’ insistence on Henry Hub pricing and the sellers’ preference for oil-linked prices—a difference that has so far been hard to reconcile.

“Project costs in Canada far exceed counterpart projects in the United States where the natural gas market is much more liquid,” the report stated. “Moreover, the distance between the proposed export facilities and the North American gas pipeline grid is large, and connections are small in both capacity and number.”

Exporting Henry Hub–linked LNG is risky because it forces sellers to produce no matter what happens to Henry Hub, at a production cost largely divorced from the Hub. “This is a problem because western Canada shale gas will likely be more expensive than the marginal acreage that sets Henry Hub prices. Despite numerous marketing leads for western Canada’s slate of projects, there are currently no finalized agreements with Asia Pacific buyers,” the IGU noted.

A few projects have attempted to circumvent this issue by creating an integrated project, where likely off-takers have stakes in the upstream. This is the case with the Royal Dutch Shell plc–led LNG Canada and Pacific NorthWest LNG, proposed by PETRONAS; both projects include Asian players in their upstream and liquefaction ownership structures that would likely take LNG back to their OIL & GAS INQUIRER • OCTOBER 2013

17

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home markets, though internal transfer pricing would need to be negotiated between the partners.

In 2012, Asian buyers started to talk openly and repeatedly about shifting from the traditional, fi xed-destination, long-term, oil-linked LNG contract. BP p.l.c. and The Kansai Electric Power Co. Inc. signed one deal linked to Henry Hub, while Japanese utilities intensified their interest in U.S. LNG and the Henry Hub– based pricing this entails.

But the cracks in the oil-linked system in Asia are few so far, the report said. To accelerate a breakthrough, Asian buyers would need to fi nd more traditional sellers willing to sell them LNG at non-oil-indexed pricing.

But for higher-cost future suppliers like Australia, western Canada and potentially East Africa, even a partial indexation to Hub-based pricing may be difficult to financially justify, as they are closely tied to the oil price and because liquefaction and upstream project costs are high.

“Since the visibility of energy markets is so short, locking in long-term contracts between sellers and buyers has been and will continue to be challenging when negotiating contracts for new projects. For shorter-term deals, though, creativity between parties may help to conclude new supply deals,” the report stated.

— DAILY OIL BULLETIN

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Painted Pony production climbs in second quarter

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OCTOBER 2013 • OIL & GAS INQUIRER

Painted Pony Petroleum Ltd. reported average daily production of 7,928 barrels equivalent per day in the second quarter, which was up from 5,745 barrels per day compared with 2012.

Painted Pony continues to pursue the development and expansion of its Montney gas assets in northeastern British Columbia.

During the second quarter of 2013, the company drilled a second 100 per cent well on the 91-F/94-B-16 pad, targeting the upper Montney. To date during 2013, the company has drilled or is currently drilling a total of eight (5.6 net) Montney horizontal wells.

A further five (four net) horizontal wells are expected to be drilled during the balance of 2013, including two (two net) new wells on the liquids-rich project at Townsend.

In the second quarter of 2013, the company equipped two 100 per cent working interest wells on the 11-J/94-B-09 pad, which were completed and tested during the first half of 2013 on lands acquired in December 2012. Earlier this year, Painted Pony announced two 100 per cent working interest wells in the Townsend block.

These wells proved to be a challenge to bring on production due to their robust wellhead flow rates and high associated liquids content, said the company. Both wells have experienced intermittent production due to area facility constraints associated with the higher-than-expected gas production rates and free condensate liquids yields of the wells.

The Lower Montney well on the Townsend 11-J pad was produced for 7.1 days during the second quarter of 2013, and it flowed at

British Columbia

The Upper Montney well on the Townsend 11-J pad was then produced for a period of 5.2 days during the second quarter of 2013, at which time it flowed at approximately 2,230 barrels equivalent per day of field-estimated raw gas, including wellhead condensate.

approximately 1,819 barrels equivalent per day of field-estimated raw gas, including wellhead condensate. This well has continued to produce through a third-party facility since early July.

The Upper Montney well on the Townsend 11-J pad was then produced for a period of 5.2 days during the second quarter of 2013, at which time it flowed at approximately 2,230 barrels equivalent per day of field-estimated raw gas, including wellhead condensate.

This well is expected to remain shut in until late in 2013, when a new operated gas processing facility, including enhanced liquidshandling capacity, is expected to come on stream. This facility will have sufficient additional capacity for the next two Townsend wells planned for the fourth quarter of 2013.

During the second quarter of 2013, Painted Pony drilled a second 100 per cent working interest Upper Montney horizontal well on the 91-F/94-B-16 pad at Blair. The two Upper Montney wells on this pad were subsequently completed and tested, and have now been placed onto production, after flowing at a total peak 24-hour rate of 15.3 million cubic feet of gas per day. They were completed using different completion and stimulation techniques.

One was completed using an open-hole ball-drop system, and the other was completed using a cased-hole perf-and-plug system. The company continues to closely monitor the performance of these wells, as they provide important comparative data concerning the efficiency of open-hole ball-drop completions in the Blair area.

Previously, Painted Pony had enjoyed success with ball drop–style completions in the Townsend area.

In the third quarter to date, Painted Pony has drilled two 100 per cent working interest Montney horizontal wells on the 14-F/94B-16 pad targeting the Middle Montney and the Lower Montney.

These wells are scheduled to be completed immediately and tied in to the Blair Creek gas plant for testing and production.

In the first quarter of 2013, two (0.4 net) additional horizontal wells were drilled on the Gundy 75-J/94-B-09 pad and are currently being completed and production tested. Test results from these wells are expected later in the third quarter.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • OCTOBER 2013

19

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NORTHWESTERN ALBERTA WELL ACTIVITY AUG/12

AUG/13

Wells licensed

217



AUG/12

AUG/13

Wells spudded

181



AUG/12

AUG/13

176



Rigs released

▲

▲

▼

Source: Daily Oil Bulletin

N.W. Northwestern Alberta

Higher Peace River production drives Baytex growth Baytex Energy Corp. reported heavy oil production averaged 42,510 barrels per day in the second quarter of 2013, driven largely by growth at its Peace River operations. The production boost represents an increase of 13 per cent over the fi rst quarter of this year. In its heavy oil business during the second quarter, Baytex drilled 23 (20.6 net) oil wells with a success rate of 100 per cent.

Production from its Peace River–area properties averaged about 23,000 barrels per day in the second quarter, an increase of 22 per cent over the fi rst quarter of this

year. In the second quarter, the company drilled 17 (17 net) cold horizontal producers in the Peace River area, bringing its year-to-date drilling to 23 (23 net) wells.

Of the 23 wells drilled during the fi rst half of 2013, 22 had average 30-day peak production rates of about 700 barrels per day. Baytex plans to drill about 14 multilateral horizontal wells during the rest of 2013.

Successful operations also continued at the company’s 10-well Cliffdale cyclic steam stimulation (CSS) module with second-quarter production averaging about 400 barrels per day. During the

quarter, fi fth-cycle steaming began on the initial Cliffdale pilot well with production flowback start-up in mid-June.

Current production from the Cliffdale CSS project is about 700 barrels per day.

Facilit y constr uction at the new Cliffdale 15-well CSS module is well underway, as drilling began in the second quarter.

Baytex expects to complete construction of the plant and start cold production in the fourth quarter. First-cycle steaming of the wells is expected in the first half of 2014.

In its Lloydminster heavy oil area, Baytex drilled four (1.6 net) horizontal

23,000 barrels per day

Photo: Aaron Parker

Baytex’s second-quarter Peace River production

and two (two net) vertical wells in the second quarter.

In the fi rst quarter of this year, Baytex drilled one thermal infill well at its Kerrobert, Sask., steam assisted gravity drainage (SAGD) project. This well began production in the second quarter, producing about 400 barrels per day.

Baytex plans to drill about 50 net wells in the Lloydminster area by year-end 2013, including one thermal infi ll well and one SAGD well pair at Kerrobert.

At Angling Lake, construction of the Gemini SAGD pilot project facilities began late in the second quarter. Construction of the drilling pad is complete, mechanical crews have been mobilized and major equipment is being moved on site.

Baytex expects to drill the SAGD well pair during the third quarter and is on track for steaming late this year or early 2014.

Baytex plans on drilling 14 multilateral wells in its Peace River heavy oil play in the remainder of the year.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • OCTOBER 2013

21

Northwestern Alberta

Delphi using slickwater fracs to drive Bigstone growth

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OCTOBER 2013 • OIL & GAS INQUIRER

Delphi Energy Corp.’s use of new completion techniques is producing some of the top liquids-rich wells drilled in the Deep Basin over recent months, according to the company’s second-quarter fi nancial and operational results.

“The slickwater program obviously is working, and we will continue to optimize that,” David Reid, president and chief executive officer, said at the company’s second-quarter results conference call. He noted the company’s 10-27-060-23W5 well at Bigstone East was still producing over 1,150 barrels equiva lent per day after 120 days, which shows the potential of such a completion technique. The 15-10-060-23W5 well, also slickwater fractured, was producing 516 barrels per day after 120 days.

In the second quarter, Delphi’s capital spending primarily included the completion and tie-in operations of the third Montney well of the winter capital program, representing 64 per cent of expenditures in the quarter. The well was successfully completed using the slickwater hybrid fracture stimulation technique.

The well (16-23-060-23W5) is reportedly outperforming expectations with initial declines significantly less than the original Montney wells in the area. This production performance significantly improves operating netbacks and reduces the expected time to pay out the wells.

“I think it is pretty clear the data we have presented validates our thesis of the benefits of the slickwater frac system, for which we were really the first to try this far east in a more normally pressured Montney system,” said Reid.

Three previously drilled wells at Bigstone East used conventional gelled oil frac designs.

With the new completion techniques accomplishing the company’s goal of significantly reducing declines, the gap between the production rates of these two new wells compared to the fi rst three continues to widen. Both wells (10-27 and 15-10) continue to exceed the current type curve. In addition, the new wells continue to produce at higher field-condensate-to-gas ratios compared to the first three wells.

The application of extended-reach horizontal drilling across two sections and stimulating using a 30-stage frac design reduces overall capital requirements and generates significantly more royalty credits, the company said. The number of days to drill to a total depth of almost 6,000 metres across two sections has decreased to 33 days from 48 days.

“That is a significant drop from the fi rst well we drilled across two sections,” Reid said.

On average, the cost to drill across the second section has decreased to approximately $750,000, compared to drilling a new well across the second section at an estimated cost of $4.5 million, Delphi said. In addition, incremental royalty credits of approximately $4.5 million are earned by drilling across the second section.

Northwestern Alberta

For the three months ended June 30, 2013, Delphi recorded average daily production at 7,635 barrels equivalent per day, which is a 12 per cent decrease from the same time frame last year. For the fi rst half of 2013, production totalled an average 7,578 barrels per day, which is 14 per cent below the fi rst half of 2012. Production volumes were reportedly impacted by scheduled facility outages in all core and several other areas, but most significantly at Bigstone East, where the company’s higher netback revenue stream from the Montney was shut in for 30 days during the quarter. However, all production was back on stream in early July.

The company intends to drill three more Bigstone East wells prior to the end of 2013, with two of those wells scheduled for completion by year-end. Wet weather delayed rig movement to the first location.

“As expected and as usual, it was a very quiet quarter from a field-operation perspective due to spring breakup,” Reid said.

“The prolonged wet weather through June and into July had delayed us a little bit in terms of our start to the second half of the drilling program, but we do have one rig drilling today…and the second rig is now on the move, and we should be spudding early next week.

“So we’re kind of back on track with the worst of the weather largely behind us, and we look forward to a very active and successful second half.”

Reid said his company would anticipate the next well results to be available sometime in October, as the company drills and completes its next well.

During the second quarter, Delphi invested $7.36 million towards capital expenditures, which is 35 per cent less than the same time frame in 2012. For the first half of the year, the company spent $43.45 million on capital expenditures, which is 33 per cent below the same six-month period last year.

In what is expected to be a continuous one-rig drilling program with up to eight wells in 2014, Delphi plans to add a second rig to the program in the latter part of 2014.

In addition, the company has started drilling operations on its southern Bigstone strat test and horizontal Montney well as part of the previously announced industry farm-in, whereby Delphi will earn a 75 per cent working interest in 32.5 sections of Montney lands. The well, with a surface location at 05-08-059-22W5, will be completed, equipped and pipeline connected in 2014 as part of the planned 15-kilometre pipeline expansion from a Delphi-owned facility to the wellsite.

Reid said, “We’ve got a good start on that and we expect the strat-test portion of the well to be completed within the next three to four weeks, and then we will be proceeding with the horizontal section to be drilled in the Montney. This well is quite a bit south on the farm-in lands from where we had our last six wells drilled, so it is an important data point for us to gather, and so far everything looks as we would expect.”

Delphi management expects net capital spending for all of 2013 to be between $78 million and $82 million, with production for the year to average approximately 8,000–8,400 barrels equivalent per day. For 2014, the company estimates production to average between 9,500 and 10,000 barrels per day, with a capital program of $80 million to $90 million.

OIL & GAS INQUIRER • OCTOBER 2013

23

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NORTHEASTERN ALBERTA WELL ACTIVITY AUG/12

AUG/13

Wells licensed

143



AUG/12

AUG/13

Wells spudded

115



AUG/12

AUG/13

107



Rigs released

▲

▲

N.E.

Northeastern Alberta

▲

Source: Daily Oil Bulletin

Suncor attempts to reclaim fen landscape

By Deborah Jaremko

Photo: Joey Podlubny

Suncor Energy Inc. has officially launched a reclamation project aimed at recreating from disturbed oilsands mining sites one of the Alberta boreal forest’s most common but challenging landscapes, a type of wetland called a fen.

The Regional Municipality of Wood Buffalo, exclusive home to oilsands mining and also the vast majority of thermal production projects, is naturally about 50 per cent wetlands, with the fen being the most

Nearly half the land in Wood Buffalo is wetlands, so successful reclamation of the fen landscape is imperative.

prevalent. The ability for oilsands operators to successfully construct this ecosystem is therefore seen as a significant step forward in operational performance and social licence.

But doing so is also incredibly difficult, which makes Suncor’s leaders excited about what they have achieved in progressing the project over the last five years through collaboration with several universities across Canada and the United States, as well as industry counterparts. The fen’s opening follows Suncor’s successful reclamation of the first tailings pond in the oilsands industry to a solid surface three years ago, which is also seen as a major milestone.

“I was involved in a hearing six years ago and people said that you couldn’t reclaim a tailings pond, and that the wetlands could never be reconstructed. In the last three years, both of those things have happened,” said Mark Little, Suncor’s executive vice-president, oilsands and in situ, at the fen site near the company’s integrated mine and upgrader base plant north of Fort McMurray. “We need to be able to accomplish these things and have these successes to be able to live up to our commitment to restore this land back to traditional use.

This is huge for us to be able to continue to make these steps forward, and these are huge strides.”

The Government of Alberta’s first Guideline for Wetland Establishment on Reclaimed Oil Sands Leases, released in 2000, referenced scientists’ assertions that “the total duplication of natural wetlands is impossible due to the complexity of restored systems and the subtle relationships of hydrology, soils, vegetation, animal life and nutrients.” The Provincial Wetland

Restoration/Compensation Fact Sheet, issued by Alberta Environment in 2005, likened this to being “almost impossible,” and in the province’s latest wetlands recreation guidelines, released in 2007, that language has been removed altogether.

For Suncor and its partners, developing the new project, dubbed Nikanotee Fen, is a challenge, but they do not see it as insurmountable. Nikanotee, a name gleaned through a contest with local elementary school students, is Cree for future.

“I think it’s future in the context that this is our future, to be able to create landscapes like this, and also the future of our neighbours. This will be used for future land use, so our neighbours are highly interested in us putting this back in a manner that they will be able to use it in the future,” said Little. “Six different universities have been involved, several of the companies are helping to do the monitoring, so this has been a huge challenge, but we’re super excited about the progress that we’ve been making.”

Christine Daly, Suncor’s aquatic reclamation research coordinator, described the three-hectare fen as the focal point of a 32-hectare constructed fen watershed. The fen is fed through an underlying watershed the company completed in January 2013 and features vegetation planted this spring and summer.

“We placed a liner under this entire area,” Daly said. “We have tailings sand on top of it, and we reused our cover soils.

We brought forest floor soils and placed them in the upland, and then we took two metres of peat from a natural fen that was about to be disturbed by mining and we reused it and placed it here. As it rains and it snows, as it did a lot this year, it brings all the water either by surface runoff or by groundwater to this lower area.”

Daly explained that “natural wetlands succession happens where you have a lake or a marsh, and as the plants grow they OIL & GAS INQUIRER • OCTOBER 2013

25

Northeastern Alberta

will fi ll in and eventually become a fen or peatland as they accumulate the soil. We’ve moved peat to this area, we’ve put typical fen plants on, we’ve built the watershed to keep the peat wet and the fen plants growing. We’ve set certain milestones to ensure

that it is a fen once more, and that’s making sure there is enough water to keep it wet… and we’ve achieved that and we’re going to keep monitoring to ensure that. We want to make sure typical fen plants are here—and they are—and they continue to thrive. And

the third [milestone] is peat accumulating.

So the universities are monitoring that.”

Based on knowledge from the peatharvesting industry in eastern Canada, Daly said Suncor expects to see those milestones within the fi rst two to five years.

Laricina’s Germain project under budget

By Pat Roche

26

OCTOBER 2013 • OIL & GAS INQUIRER

Saleski’s first commercial phase is estimated to cost $520 million ($312 million net Laricina). Laricina is the operator and 60 per cent owner of the Saleski pilot and planned commercial project. Its joint-venture partner, privately held Osum Oil Sands Corp., said it is fully funded for its 40 per cent share of the commercial project.

Laricina reported a strong working capital position of $221.6 million exiting the second quarter—after the startup of Germain.

Laricina president and chief executive officer Glen Schmidt declined to disclose exactly how much money the company needs to raise specifically for the Saleski commercial phase. He said more detail on Laricina’s 2014 capital plans will emerge when its budget is released in the fourth quarter.

But, in total, the company expects to seek financing of $500 million to $600 million, which could be completed in more than one step, to meet its needs over the next couple of years, Schmidt said.

But besides the Saleski commercial project, he said that money would include funding for Germain Phase 2, ongoing drilling and seismic work, and infrastructure such as roads and pipelines.

As it has done since its incorporation in late 2005, Laricina is pursuing private capital markets. An initial public offering hasn’t been scheduled because the public markets are currently unfavourable to oil and gas stocks.

With production set to begin shortly, “we think we’re ready for the public markets,” Schmidt said, “but we’ll clearly wait until they’re ready for us.”

Depressed share prices and the difficulty of raising money were common refrains at the annual meetings of many conventional oil and gas producers in

Laricina president and chief executive officer Glen Schmidt. Laricina’s cost for its Germain project will be $410 million, $25 million less than forecast.

Calgary this year. The softness of global capital markets has also affected small oilsands projects.

For example, BlackPearl Resources Inc. chose to proceed first with development of a planned 12,000-barrel-perday thermal heavy oil project at Onion Lake in Saskatchewan before tackling the 20,000-barrel-per-day commercial phase of its Blackrod steam assisted gravity drainage (SAGD) project in the Alberta oilsands. BlackPearl cited the high cost and challenge of raising funds for large projects in current capital markets.

And Sunshine Oilsands Ltd. suspended construction of the central processing facility at its 10,000-barrel-per-day West

Photo: Joey Podlubny

Laricina Energy Ltd. continues to seek fi nancing for the fi rst commercial phase of its Saleski bitumen carbonates project as it prepares for fi rst oil from Germain in the conventional oilsands.

The privately held oilsands developer began injecting steam into the Grand Rapids Formation at Germain on June 8, a milestone marking the start of operations for its first commercial-scale project.

And in a positive development that bucks the trend in oilsands construction, Laricina expects the capital cost of building and commissioning the 5,000-barrel-perday Germain project will be $410 million— $25 million less than its previous forecast. The estimate includes a fourth steam generator, a third dilbit tank and the solvent-recovery unit construction and commissioning that will continue into 2014.

Completing an oilsands project on time and below cost is an achievement at a time when many such ventures have experienced cost and schedule overruns.

Meanwhile, the timing of the groundbreak ing f irst commercial phase of Laricina’s Saleski project—which will have the capacity to produce up to 10,700 barrels per day of bitumen from the Grosmont carbonate formation—will depend on the company’s ability to raise financing.

So far, no one has achieved commercial production from Alberta’s bitumen-bearing carbonate rock, which is thought to hold an even bigger in-place oil resource than conventional bitumen formations such as the McMurray. Success would open a new frontier in the development of Alberta’s oilsands.

Laricina has been operating a pilot at Saleski since 2011. The estimate of first commercial oil from Saleski by late 2015 assumes project sanction in the fourth quarter of this year, which in turn depends on securing financing.

Northeastern Alberta

Ells oilsands project in the Athabasca oilsands region until it secures further funding. The company said flooding in June added to the cost pressures at West Ells, raising the estimated price tag to $525 million. In April, the estimated cost of West Ells was still on budget at $468 million, excluding road construction. Sunshine said it is looking to secure financing of up to $300 million so it can continue to advance its projects.

However, Schmidt believes oilsands stocks are poised for improvement with significantly narrowed heavy/light oil price differentials and TransCanada Corporation’s decision to seek regulatory approval for a major oil pipeline to the east coast.

Schmidt said preliminary engineering for the Saleski commercial project has been done and detailed engineering is underway.

“So the major capital requirements of procurement and construction will require funding,” he said. “But we’ve managed both our timing and our working capital that we have sufficient time to do that.”

With regulator y approval for the Saleski commercial phase received earlier this summer, the company can now focus on raising money.

Meanwhile, Laricina said the Germain commercial demonstration project is fully funded, as is the continued operation of the Saleski pilot.

Germain is the first commercial-scale test of Laricina’s proprietar y solventcyclic SAGD (SC-SAGD), which adds solvent to steam injected into the reservoir over certain time inter vals. This process is designed to lighten the produced oil, lower the steam to oil ratio and cut carbon emissions.

In the second quarter, the Germain operating team began well start-up by injecting steam into two production wells followed by steam injection into the associated injection wells shortly thereafter.

Laricina expects the warm-up of seven well pairs will take roughly three to four months. Well pairs will then be converted to SAGD production.

First oil at Germain is expected to flow in the third quarter.

Laricina expects to introduce SC-SAGD in four producing well pairs early in 2014.

Construction continues on the solvent recovery unit to capture solvent returns from production.

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27

413088 Annugas Compression Consulting Ltd full page 路 fp Cen AB News

CENTRAL ALBERTA WELL ACTIVITY AUG/12

AUG/13

Wells licensed

267



AUG/12

AUG/13

Wells spudded

280



AUG/12

AUG/13

266



Rigs released

▼

▼

▼

Source: Daily Oil Bulletin

C.A.B. Central Alberta

Wilrich play taking off

By Paul Wells

The early promise of the Wilrich natural The firm reported that results continue barrels of liquids per million cubic feet (40 gas play in Alberta’s Deep Basin is coming to be strong, with total Wilrich natural gas per cent condensate). First-year decline is to f ruition as operators continue to volumes at approximately 0.42 billion cubic about 70 per cent, EUR per well is 4.4 bilramp up activity and well results remain feet per day, representing a 53 per cent lion cubic feet and all-in well costs are in encouraging. increase year-over-year. the $5.5-million range.

Jeremy McCrea, an analyst with “While it is certainly expanding, we McCrea said that recent Wilrich wells AltaCorp Capital Inc., said that only a few continue to believe the development footdrilled by industry continue to impress, years ago the Wilrich was “completely off print of the Wilrich is relatively compact but because the zone covers a vast expanse, the radar screen.” Now, with the continued compared to the size of the prospective fairresults can vary greatly. advancement of horizontal drilling, multiway and that the number of producing fields “It’s still quite variable because the stage fracturing and completion techniques, should continue to grow,” Peters stated.

Wilrich channels extend all the way throughout the Deep Basin, so depending the play is evolving at a strong pace.

According to the report, recent data “In this last year, it has really started to shows that Wilrich wells at Edson/Nosehill on where you are in the Deep Basin, it does take off, and Tourmaline Oil Corp. has been have average 30-day initial production vary,” he said. at the forefront of it and Peyto Exploration and Development Wilrich original petroleum in place Corp. is close behind,” he said, noting that industry heavyHYDROCARBON LOW ESTIMATE MEDIUM ESTIMATE HIGH ESTIMATE weights Encana Corporation, Oil (billion bbl) 20.2 47.9 172.3 ConocoPhillips Canada, Natural gas liquids (billion bbl) 0.7 2.1 4.4 Husky Energ y Inc. and Canadian Natural Resources Natural gas (tcf) 115 246 568 Limited are also active in Natural gas—adsorbed gas content (%) 6.2 33.7 59.2 the Wilrich.

Source: Alberta Energy “If you look at where the top Crown land sales have been recently, the $4,400 per hec(IP30) rates of 3.8 million cubic feet per TOURMALINE LEADING THE CHARGE tare around the Minehead region is a day with liquids yields of between 10 and Tourmaline Oil Corp. began operations top new area of focus for [the] guys, 35 barrels per million cubic feet (40 per just over four years ago and quickly began assembling a large position in the Deep and the play that they’re chasing is cent condensate). The fi rst-year decline is the Wilrich.” about 60 per cent, and the estimated ultimBasin, with the Wilrich being viewed as one “The Wilrich continues to rank as one of ate recovery (EUR) is 4.7 billion cubic feet of the company’s prime targets. the most-active and fastest-growing plays equivalent. All-in costs for a typical well in “Then we developed the Deep Basin in the Western Canadian Sedimentary this area are $5.2 million. vertically and horizontally, and it looked Basin,” said Peters & Co. Limited in a recent In the Kakwa/Resthaven region, IP30 like a good horizontal candidate, so we report on the play. rates average about eight million cubic feet really just focused on three formations According to Peters, about 40 Wilrich horizontally—the Cardium, the Notikewin per day with about 25 barrels of liquids per wells were added during the fi rst quarter, million cubic feet (40 per cent condensate). and the Wilrich,” president and chief execbringing the total count to about 250 wells.

First-year decline is 60 per cent, EUR is 9.1 utive officer Michael Rose said. “So far, the The number of wells with more than one billion cubic feet and all-in well costs averhorizontal Wilrich results have been the month of production increased 26 per cent age about $8 million. best of the three, and they’ve been stellar.” to 205, giving the fi rm a broader sample At Sundance, IP30 is estimated at 4.7 Buoyed by initial results, Rose said size to work with in its analysis. million cubic feet per day with about 10 that Tourmaline got after the Wilrich OIL & GAS INQUIRER • OCTOBER 2013

29

Central Alberta

in earnest early in the second half of 2012 and has since continued to ramp up activity in the play.

“In aggregate to date, I think we’ve got 38 wells drilled and probably 34 tested. We’ve got six rigs focused on the Wilrich right now, and for calendar 2013 the goal is to drill somewhere between 45 and 50 Wilrich wells, and we’d like to get them drilled, completed and the vast majority on stream,” he said.

Well costs are trending down as the company gains experience and knowledge of the play.

“I think we are wearing costs down.

I think we’re carrying an average of $5.25 million per horizontal right now, and we think we can take that down further when we do more pad drilling,” Rose said.

Tourmaline’s first 38 Wilrich wells have been broadly positioned over an asset base that stretches about 250 kilometres from one end to the other. Rose said that with six rigs now running, optimization from pad drilling is set to begin.

“We’re going to do two- and three-well Wilrich pads and we’ll frac two or three wells

wheRe dO we PUT

at a time, and then you start seeing some cost savings, on your completions especially,” he said.

“We think we will probably ultimately get the costs down to between $4.5 million and $4.75 million for a completed horizontal.”

Rose said that this year’s drilling program of 45–50 Wilrich wells is likely the company’s blueprint for Wilrich development going forward.

PEYTO IS BIG ON THE WILRICH Peyto Exploration and Development Corp.’s Wilrich program has been a vital component of its operational focus since the company turned to horizontal drilling in late 2009 and early 2010, and will remain so going forward.

“In terms of well count, if we were to look at the last several years of drilling, the Wilrich has been roughly one-third of the number of wells,” executive vice-president and chief operating officer Scott Robinson said.

“This year we’re looking at a capital program that sees us drilling about 100

wells in 2013, and roughly a third of those will be Wilrich. It has been, and continues to be, a very important part of our ongoing program.”

Peyto is focusing on the Wilrich in its Sundance and Nosehill core areas, which means there can be slight variations in well results and costs.

“Overall, the Wilrich program has been very consistent since inception in terms of production performance. Yearover-year average production cur ves almost overlap without fail, proving that there hasn’t been any overall deterioration in the performance of the new wells we drill as compared to the fi rst wells back in the beginning.”

Robinson said that Peyto’s Wilrich wells typically have average IP30 rates in the four-million-cubic-feet-per-day range, and after one year will decline to between 1.5 million and two million cubic feet per day.

All-in well costs have decreased to between $4 million and $5 million as efficiencies continue to be gained.

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OCTOBER 2013 • OIL & GAS INQUIRER

Central Alberta

Retooled legacy sour gas plants taking on new role

By Elsie Ross

Western Canadian midstream operators are looking at how they can retool old, underused sour natural gas plants to meet the needs of today’s producers for increased natural gas liquids (NGL) fractionation capacity from gas that is either sweet or only slightly sour, an NGL conference heard last month.

“These legacy gas plants have the capacity available, and they are regionally proximate to the Duvernay and the Montney zones,” David Williams, vice-president and general manager of SemCAMS, said in a presentation to the NGL Markets & LNG Export Congress. “[A] key question being asked by many in this Montney region is, can these old facilities that were designed for different gas compositions handle this new-era gas?”

Most of the plants were built in the 1970s for high sulphur–content gas that was fairly lean, and the NGL recoveries were only what were needed to meet the

hydrocarbon dewpoint on downstream pipelines. There was no market for ethane and only a limited market for NGLs, and their value was similar to that of the British-thermal-unit content of the gas, he said.

Sulphur production in western Canada peaked in 1999, and since then has fallen by about one-third despite increased sulphur production from the oilsands, the conference heard.

“The implication is that many sour gas processing plants that need sulphur to fi ll their sulphur recovery units are approaching the turndown levels at which they can’t operate within their licensed recovery levels,” said Williams, whose company operates the Kaybob South #3 and Kaybob Amalgamated plants in northwestern Alberta. The result, he suggested, could be processing plant shutdowns and consolidations.

No significant new sour processing facilities have been built in recent decades, in part due to cost pressures, he told the conference sponsored by Canadian Business Conferences Limited. Because of the difficulty in obtaining regulatory permits for new sour plants, new sour production will go either to an existing sour plant or to new facilities with acid gas injection as an alternative to sulphur recovery.

Although the use of existing plants will avoid permitting delays, facilities will have to adapt to handle new-era gas, said Williams. That will include the ability to handle gas with less sulphur, to provide a higher NGL recovery and to handle more liquids, primarily condensate. There also is a need to ensure producers have access to markets, he said.

One way to deal with reduced sulphur in the gas, which can make sulphur recover y units unstable, is to lower

OIL & GAS INQUIRER • OCTOBER 2013

31

Central Alberta

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the inlet sulphur rate so that a smaller percentage of sulphur will have to be recovered. If that’s not enough, sour production could be shut in and the plant converted to sweet-only service, but that would affect producers, especially those in the Montney who have sour gas, said Williams. A processor can also modify the sulphur recover y unit (SRU)—an expensive process—build a new, smaller SRU, or simply inject acid gas into a depleted reservoir.

When it comes to increasing NGL recovery rates, one option is a deep-cut cryogenic facility, but that often isn’t the best solution because they are expensive both in terms of capital and operating costs, and will currently add little value in Alberta, he said.

“Decline rates and uncertain volumes in the field sites make investing in a deep-cut facility at a field site a risky venture.”

— David Williams, vice-president and general manager, SemCAMS

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OCTOBER 2013 • OIL & GAS INQUIRER

“Decline rates and uncertain volumes in the field sites make investing in a deep-cut facilit y at a field site a risky venture.” Straddle plants might be a better place to recover the ethane, Williams suggested.

Lean oil absorption facilities such as those at SemCAMS’ Kaybob plants also can be effective at recovering NGLs other than ethane, he said. At its K3 plant, the company is now recovering more than 90 per cent of the propane.

In order to handle more condensate at the front end of the sour plant, large separators at the plant inlets and larger condensate stabilizers are added to make condensate stable so t hat it ca n be shipped as a product on the pipeline.

More storage capacity is also needed. If pipelines cannot expand fast enough to handle increased condensate volumes, plants also need to develop truck- and rail-loading facilities.

SOUTHERN ALBERTA WELL ACTIVITY AUG/12

AUG/13

Wells licensed

67



AUG/12

AUG/13

Wells spudded

80



AUG/12

AUG/13

Rigs released





▲

▲

▲

Source: Daily Oil Bulletin

S.A.B. Southern Alberta

Spyglass Resources output up

Photo: Joey Podlubny

Spyglass Resources Corp., which started operations after a business combination in the first quarter, reported an increase in production to 16,362 barrels of oil equivalent per day, compared to 13,765 barrels in the second quarter of 2012.

On March 28, Spyglass completed a business combination by way of a plan of arrangement with Pace Oil & Gas Ltd., AvenEx Energy Corp. and Charger Energy Corp. whereby Pace, AvenEx and Charger exchanged all of their issued and outstanding shares for common shares of Spyglass.

Oil and liquids production represented 48 per cent of total production at 7,924 barrels per day, an increase of 1,549 barrels per day, or 24 per cent, from 6,375 barrels per day in the second quarter of 2012.

Second-quarter 2013 results reflected the first complete quarter with production contributed from AvenEx and Charger, which accounts for the majority of the reported production increase.

The company’s field-estimated July production increased to approximately 16,900 barrels of oil equivalent per day, reflecting the success of production optimization initiatives.

Capital expenditures for the second quarter of 2013 were $8.28 million, focused primarily on workovers, optimization and maintenance operations.

In the second quarter, Spyglass initiated the 2013 development drilling program, heavily weighted to the third and fourth quarters, with emphasis on achieving strong capital efficiencies. To date, the company has drilled seven horizontal light oil wells in southern and central Alberta.

In southern Alberta, the company has drilled and completed five horizontal wells targeting the Pekisko and Glauconite zones. The 2013 capital program includes one additional follow-up Glauconite location in southern Alberta.

Preliminar y indications from the first Pekisko and Glauconite wells have exceeded management expectations with pump-constrained inf low volumes in excess of 300 barrels per day per well and oil rates in excess of 100 barrels per day per well, and the wells are continuing to clean up.

The company also participated in two (0.67 net) oil wells in the quarter in the

Glauconite channel play, with encouraging results.

In late July, Spyglass initiated an eight-well drilling program in the HalkirkProvost area, with two Viking horizontal wells drilled to date.

Drilling and completion expenditures to date in 2013 are estimated to be five to 10 per cent under budget. Production from newly drilled locations will start this month, and new wells will continue to come on stream during the third and fourth quarters of 2013.

Spyglass said it will defer the single Cadomin natural gas well originally contemplated for the fourth quarter of 2013 at Noel due to the lower natural gas price outlook. As a result, the 2013 capital program is expected to total $67 million, including drilling 20 (17 net) light oil wells.

Management is revising its 2013 exit production guidance to 17,000–17,500 barrels of oil equivalent per day (51–53 per cent oil and liquids), as a result of the deferral of the Noel Cadomin well.

— DAILY OIL BULLETIN

Spyglass drilled five oil wells in southern Alberta in the second quarter, with initial production averaging over 100 barrels of oil per day.

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Cover Feature

Set to

SOAR Canadian industry faces challenges and opportunities as U.S. reverses decline in domestic petroleum production

By Darrell Stonehouse

Talk about a remarkable turnaround.

Five years ago, the U.S. petroleum industry was in a state of steady decline. Oil production had dropped from a peak of nine million barrels per day in 1985 to just five million barrels per day in 2008. Natural gas production fared a little better, rising by three billion cubic feet per day during the 23-year period.

Then came the extended-reach horizontal drilling and multistage fracturing revolution. Over the last half a decade, oil production has climbed 43 per cent to reach 7.3 million barrels per day. Dry gas production has climbed by 4.5 billion cubic feet per day in the last five years, more than in the previous 20 years.

Oil and gas reserves are on an even more impressive upward trajectory. U.S. proved crude oil reserve additions in 2011 set a record for the second year in a row, according to U.S. Crude Oil and Natural Gas Proved Reserves, 2011, released in early August by the U.S. Energy Information Administration (EIA). Natural gas proved reserves also rose, but by less than 2010’s record increase. Nevertheless, natural gas reserves additions in 2011 rank as the second largest annual increase since 1977.

36

OCTOBER 2013 • OIL & GAS INQUIRER

“Horizontal drilling and hydraulic fracturing in shale and other tight rock formations continued to increase oil and natural gas reserves,” says EIA administrator Adam Sieminski. “Higher oil prices helped drive record increases in crude oil reserves, while natural gas reserves grew strongly despite slightly lower natural gas prices in 2011.”

Proved oil reserves, including both crude oil and lease condensate, increased by 15 per cent in 2011 to 29 billion barrels, marking the third consecutive annual increase and the highest volume of proved reserves since 1985. Proved reserves in tight oil plays accounted for 3.6 billion barrels (13 per cent) of total proved reserves of crude oil and lease condensate in 2011.

Natural gas proved reserves, estimated as wet gas that includes natural gas liquids, increased by almost 10 per cent in 2010 to 348.8 trillion cubic feet, the 13th consecutive annual increase. Proved reserves in shale gas plays accounted for 131.6 trillion cubic feet (38 per cent) of total proved reserves of wet natural gas in 2011.

What is most impressive about the rise in U.S. production and reserves is that it’s just beginning. And this will provide challenges and opportunities for Canada’s oil and gas producers.

Cover Feature

Tight oil plays alter the North American petroleum map Adding two million barrels per day in oil production in five years is a major accomplishment. For comparison, it is the equivalent of adding 13 integrated oilsands mines that produce 150,000 barrels per day. Making it more impressive is the fact that around 75 per cent of the new production is coming from two plays: the Bakken and the Eagle Ford. Bakken production was estimated at 860,000 barrels per day while Eagle Ford production reached 620,000 barrels per day in August.

And this is just the beginning, says Leonardo Maugeri, a former oil industry executive from Italy’s Eni S.p.A. who is now an associate at Harvard’s John F. Kennedy School of Government’s Belfer Center for Science and International Affairs.

Maugeri reviewed the performance of 4,000 U.S. tight oil wells, including an in-depth analysis of 2,000 wells, and the work of 100 companies for his study, The Shale Oil Boom: A U.S. Phenomenon. His conclusion?

“The dramatic surge in U.S. shale oil production could more than triple current American output of shale oil to five million barrels a day by 2017, which would likely make the United States the No. 1 oil producer in the world.”

If oil prices remain close to today’s levels, total U.S. production of all forms of oil could grow from 11.3 million barrels per day to 16 million by 2017, he says.

Maugeri says there are a number of reasons the shale oil boom has taken off in the United States, factors that exist nowhere outside the United States except in Canada.

These factors include the availability of drilling rigs and the entrepreneurial nature of the American exploration and production industry, both critical for the thousands of wells required for shale oil exploitation.

Maugeri says a key distinction between conventional oil development and shale oil development is the level of drilling intensity required to maintain and increase production in shale oil plays.

“Given the early state of knowledge and technology, the U.S. shale oil boom is mostly a function of bringing as many wells as possible online, due to the dramatic decline in production that follows the early months of activity with each new well,” he explains. “For example, by December 2012 it took about 90 new producing wells per month just to maintain North Dakota’s Bakken–Three Forks oil production of 770,000 barrels per day.”

Drilling intensity in U.S. shale oil plays skyrocketed from a few hundred wells brought online before 2011 to more than 4,000 in 2012—a figure that outpaces the total number of oil and gas wells (both conventional and unconventional) brought online in the same year in the rest of the world, except Canada.

In the short to medium term (three to five years), the correlation between drilling intensity and shale oil

production will shape the evolution of U.S. oil production more than any other factor, he adds.

Maugeri says the number of American shale oil wells in North Dakota and Texas could soar from the current 10,000 to more than 100,000 working wells by 2030. Only the U.S. oil industry is capable of such drilling intensity, he notes. In 2012, the United States completed 45,468 oil and gas wells and brought online 28,354 of them, compared with 3,921 wells completed in the rest of the world, outside of Canada. The United States holds more than 60 per cent of global drilling rigs, and 95 per cent of American rigs can perform horizontal drilling, which, along with hydraulic fracturing, is necessary to exploit shale oil.

“Combined with a relatively low population density in several shale areas, this vast supply is a key factor that allows the United States to achieve a drilling intensity level that is impossible for other countries to achieve,” Maugeri says. “No other country in the world has ever experienced even a fraction of the overall U.S. drilling intensity, a common feature of the U.S. oil and gas industry since its inception.”

Another factor driving the shale oil boom is the entrepreneurial spirit of independent U.S. producers, he adds, noting their “guerilla-style operational mindset has proven essential to the exploitation of shale formations that require companies to move on a micro-scale, on multiple microobjectives, and flexibly leverage short-term opportunities.”

Canadian oil still needed despite boom If Maugeri is right, and the United States becomes the world’s biggest oil producer, what does all this mean to Canada?

Not much in the mid-term, according to a new report by the Canadian Energy Research Institute (CERI).

In a report titled United States Oil Industry and Liquid Supply/Demand to 2022, CERI, citing U.S. government and private data, suggested that even with growing production, the U.S. will still require imported oil even beyond what Canada currently supplies.

U.S. oil imports have dropped to 8.3 million barrels per day from a high of 10 million barrels per day in 2005. U.S. consumption of oil and oil-equivalent liquids is more than 18 million barrels per day.

Improved fuel standards and conversion to natural gas fuels in the transportation sector could cut consumption by one million to two million barrels per day, but the rate of adoption within the transportation sector is slow and in all likelihood will not be achievable until well into the next decade, CERI says.

The report said four plays—the Bakken in North Dakota, the Eagle Ford in Texas, the Niobrara in Colorado and the Utica in Ohio—might have the potential to bring on two million to four million barrels per day of new production by the end of the decade.

However, it noted U.S. conventional production and Gulf of Mexico offshore production are in decline, resulting in

OIL & GAS INQUIRER • OCTOBER 2013

37

Cover Feature

Principal tight oil plays: Oil production and proved reserves, 2011 2011 Production (million barrels)

2011 Reserves (million barrels)

123

1,998

Texas

71

1,251

Barnett

Texas

8

118

Niobrara

Colo., Kan., Neb., Wyo.

2

8

204

3,375

24

253

228

3,628

Basin

Play

State(s)

Williston Basin

Bakken

N.D., S.D., Mo.

Western Gulf

Eagle Ford

Fort Worth Denver-Julesberg Subtotal

Other tight oil plays (e.g. Monterey, Woodford) All U.S. tight oil plays Note: Includes lease condensate.

Source: U.S. Energy Information Administration, Form EIA-23L, Annual Survey of Domestic Oil and Gas Reserves.

a potential loss of 1.5 million barrels per day, also by the end of the decade.

Canada currently exports more than 2.3 million barrels per day of conventional oil, bitumen and synthetic crude oil to the United States.

Oilsands production growth plus non-oilsands oil potential from western Canada could result in one million to two million barrels per day of new production looking for a market, possibly the United States.

Last year, the United States imported 4.49 million barrels per day from non-OPEC countries with 54 per cent of that oil sourced from Canada, 22 per cent from Mexico and nine per cent from Colombia. That was slightly more than the 4.03 million barrels per day imported from OPEC—34 per cent of which came from Saudi Arabia, 23 per cent from Venezuela and 12 per cent from Iraq.

Imports from countries other than Canada would decline to 3.1 million barrels per day by 2022 from 6.1 million barrels per day in 2012, the CERI report suggested. It cited U.S. and industry forecasts that U.S. oil imports from Canada will grow to 4.05 million barrels per day by 2022 from 2.34 million barrels per day. Mexico is assumed to export about one million barrels per day to the United States.

CERI developed a forecast of oilsands and non-oilsands volumes Canada could ship to the United States if pipeline and rail connectivity are fully developed. In this forecast, which is net of local demand, CERI has accounted for the expansion of the Enbridge Inc. Alberta Clipper Pipeline Phases 1 and 2, construction of the Keystone XL Pipeline and development of rail transport to 600,000 barrels per day.

These developments would deliver 1.4 million new barrels per day of bitumen and regular crude to the United States by 2018, the report said.

The report noted that in its Annual Energy Outlook 2013, the EIA indicated U.S. consumption of hydrocarbon-based liquids will not grow significantly from its current level. That forecast shows U.S. consumption reaching 19.8 million barrels per day by 2022.

“The trend analysis of unconventional shale oil growth…indicates that U.S. domestic supply could reach 8.9 million barrels a day by 2022,” the study said.

Marcellus to change natural gas landscape Remember the Barnett shale gas play in Texas?

In 2004, it was producing less than 100 million cubic feet per day.

Then came the arrival of horizontal drilling and multistage fracturing. Output is now over six billion cubic feet per day.

38

OCTOBER 2013 • OIL & GAS INQUIRER

Impressive, but nothing compared to what is being predicted for the Marcellus shale gas play enveloping much of the northeastern United States.

Eric Kuhle, a senior supply analyst for global consultancy Wood Mackenzie Limited, expects the Marcellus and Utica plays will account for 60 per cent of North American natural gas production growth to 2020, topping out at about 14 billion cubic feet per day.

Peter Howard, president and chief executive officer of CERI, is even more bullish. Production from the Marcellus could grow to between 17 billion and 22 billion cubic feet per day by 2030, he told a recent conference in Calgary. To put that in perspective, Canada’s peak production—reached a few years ago—was 18 billion cubic feet per day.

Addressing a conference on liquefied natural gas (LNG) and natural gas liquids hosted by Canadian Business Conferences Limited, Howard said the Marcellus shale play “is something that is really a large monster.”

He said the Marcellus today has about 2,000 wells that are shut in awaiting pipelines, and forecasts suggest an average of 2,100– 2,300 wells per year will be drilled into the play “for many, many years to come.”

The sheer size of the Marcellus and its location close to the largest consumer market in the United States are already having impacts on the Canadian industry, which has been in contraction for the last five years.

But Kuhle says Wood Mackenzie sees this decline levelling off over the next few years with the basin becoming a “growth story in the second half of the decade.”

Kuhle notes that the growth will largely be supported by continued expansion in the Montney, “which has very low and attractive gas break-even rates,” supported by the liquids-rich nature of portions of the play.

“In addition, we see continued investment occurring in the Duvernay shale and production growth accelerating for 2015 and beyond as companies move from delineation to development over the next several years,” Kuhle says.

“The WCSB [Western Canadian Sedimentary Basin] is a growth story in our long-term outlook, both from 2015 to 2020, but beyond 2020 when we see a recovery in Horn River development as our gas prices exceed $5.20 [per million British thermal units] on an average basis.”

Cover Feature

“ There are 30 gigawatts of coal-fired power that’s due to be decommissioned or shut down within the next seven years in the United States.”

— Peter Howard, president and chief executive officer, Canadian Energy Research Institute

Wood Mackenzie forecasts that Montney output will double from current levels to 5.1 bilion cubic feet per day by 2018, while Duvernay production will rise to 2.1 billion cubic feet per day by 2020.

Wood Mackenzie upstream research analyst Mark Oberstoetter says improving natural gas prices will spur on additional WCSB gas development early next decade.

“Our long-term expectation for gas prices in 2020 is $5.20 in real dollars. We think that price and the price appreciation we see post-2020 start to incent development in non-core areas in the WCSB, starting to bring in areas outside of just the Montney and Duvernay in our production outlook,” he says.

LNG, gas-fired power to spur long-term demand Despite the U.S. shale gas surge, Howard also appeared upbeat in his overall outlook for the western Canadian gas industry.

He is optimistic about the prospect of huge exports of North American gas to overseas markets. Of four potential scenarios for North American gas, Howard said a scenario he calls “LNG tsunami” is “probably where we’re headed.”

Under this scenario, strong growth in global LNG demand and the resulting high prices would drive aggressive development of LNG exports from North America.

However, the higher gas price—coupled with a politically driven U.S. energy policy supporting both coal and renewables— would partially erode the competitive advantage of gas in power generation, limiting North American gas demand. New regulations would increase hydraulic fracturing costs and limit the growth of shale gas development.

Under Howard’s LNG tsunami scenario, the influential coal lobby would be successful in extracting political concessions, and the trade-off Washington would make to get those passed would be increased support for renewable energy sources such as wind, solar, tidal or geothermal.

This underscores the urgency of capturing overseas markets for Canadian gas. Howard warned that the first exporters to start shipping LNG overseas will capture market share, while the last one in might not have a market.

Though rising gas prices and more competitive alternatives would make gas less attractive for generating electricity, Howard still believes there will be a huge opportunity for gas as aging coalfired power plants are retired.

CERI says 42.5 per cent of the power generated in the United States comes from coal.

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39

Cover Feature

Principal shale gas plays: Natural gas production and proved reserves, 2010-11 2010

2011

Production (tcf)

Reserves (tcf)

Production (tcf)

1.9

31.0

2.0

0.5

13.2

Change Reserves (tcf)

Production (tcf)

Reserves (tcf)

32.6

0.1

1.6

1.4

31.9

0.9

18.7

Basin

Shale play

State(s)

Fort Worth

Barnett

Texas

Appalachian

Marcellus

Texas-Louisiana Salt

Haynesville/ Bossier

Texas, La.

1.5

24.5

2.5

29.5

1.0

5.0

Arkoma

Fayetteville

Ark.

0.8

12.5

0.9

14.8

0.1

2.3

Anadarko

Woodford

Texas, Okla.

0.4

9.7

0.5

10.8

0.1

1.1

Western Gulf

Eagle Ford

Texas

0.1

2.5

0.4

8.4

0.3

5.9

Subtotal

5.2

93.4

7.7

128.0

2.5

34.6

Other shale gas plays

0.2

4.0

0.3

3.6

0.1

-0.4

All U.S. shale plays

5.4

97.4

8.0

131.6

2.6

34.2

Pa., W.Va., Ky., Tenn., N.Y., Ohio

Source: U.S. Energy Information Administration, Form EIA-23L, Annual Survey of Domestic Oil and Gas Reserves.

“Those coal-fi red plants are getting very, very old,” Howard said. Eighty-seven per cent of all U.S. coal-fired power plants are at least 25 years old, and 22 per cent are at least 45 years old, he said.

“There are 30 gigawatts of coal-fi red power that’s due to be decommissioned or shut down within the next seven years in the United States,” Howard said. As well, he said a similar amount of nuclear power generating capacity is supposed to come offl ine, albeit in the 2025-30 time frame.

“So this actually makes a lot of room for natural gas to move in here,” he said. “However, the U.S. renewable portfolio standard—

40

OCTOBER 2013 • OIL & GAS INQUIRER

which is a state-level standard—is forcing renewables into the marketplace. But even with that, there’s still a lot of room for growth in gas-fired generation in the United States.”

Howard showed a graph forecasting total demand for electricity in the United States will grow to 640 gigawatts by 2030 from 455 gigawatts today.

“Depending on which narrative you want to believe, natural gas used for power generation will go from 20 billion cubic feet per day to 52 billion cubic feet. So that’s more than 2.5 times,” he said of the most optimistic forecast.

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Feature

Waiting for the rebound Oilfield haulers in holding pattern until new export capacity comes on stream

T

he winter of 2012-13 was one to forget for western Canada’s oilfield hauling industry, as flat drilling numbers resulted in slow growth for everyone from rig movers to equipment haulers to fluid handlers.

That trend continued into the spring, according to Murray Mullen, chairman and chief executive officer of Mullen Group Ltd., an integrated service and trucking operation operating across North America.

“That was as nasty a quarter as I’ve seen in a long time,” Mullen said in announcing the company’s second-quarter results late this summer.

Mullen Group’s oilfield services segment second-quarter revenue totalled about $173.6 million, a $14.4-million decrease from the same time frame in 2012. The decrease is mainly due to a $12-million decline in revenue from operating entities directly tied to drilling activity, most notably from rig relocation services.

The company reported that oilfield revenue decreases were partially offset by an increase in revenue generated from the greater demand for services related to large-diameter pipeline construction projects and from the additional demand for fluidhauling services in the heavy oil resource plays.

Mullen said while the first half of 2013 has been slow, he expects it to gradually improve going forward. He said despite the lack of drilling activity in the spring, oilfield revenue only 42

OCTOBER 2013 • OIL & GAS INQUIRER

declined by 7.7 per cent, “setting us up nicely for the future when drilling activity reverts to the norm.”

Mullen said he believes things will begin to improve in the third quarter.

“We are of the view that the foundation is set for a rebound in oil and natural gas activity levels,” he noted. “Crude oil pricing remains strong, accompanied by significant optimism related to the export of natural gas from western Canada through the West Coast.”

But, he said, opportunities for real growth won’t happen until the broader economy begins righting itself.

“We just can’t get any serious momentum at this time,” he explained. “Real growth will return to the industry when Canada gets access to new markets for natural gas, as well as our crude oil.

This will mean new pipelines to deepwater ports, new infrastructure, storage terminals and plants. New and sustainable drilling will be a requirement if we, as Canadians, have the willpower and vision to sell our natural resources to new world customers.”

TransForce, a major competitor to Mullen in oilfield hauling, also reported a tough spring. Strong performance in its commercial trucking operations “were overshadowed by continued weakness in rig moving activities of the energy sector, resulting in lower year-over-year revenue for TransForce in the second quarter,” Alain Bédard, chairman, president and chief executive officer told shareholders in his second-quarter report.

Photos: Joey Podlubny

By Darrell Stonehouse

Feature

“Services to the energy sector remained considerably affected by the severe decline in drilling activity in North America, and we have taken proactive measures to better align supply to new demand levels.”

TransForce’s energy services revenues declined from almost $110 million in the second quarter of 2012 to $79 million in 2013. Bédard said he is not expecting a turnaround any time soon.

“Softness persists in the energy sector, and we do not see any short-term significant improvements,” he said.

In the longer term, however, oilfield hauling has a number of things going for it. As the use of long horizontal wells and multistage fracturing is spreading across North America, demand for hauling materials to and from wellsites is expected to skyrocket.

The volume of materials needed just to construct drill pads is huge. Construction of drill pads alone can require as many as 300 loads of gravel. Transporting rig mats to drilling sites is also a growth opportunity.

Rig moving is also expected to take off, as the intensity of drilling to maintain and grow production in high-decline tight oil and shale gas plays across North America increases. The current drilling fleet of around 1,840 rigs moves around 43,000 times per year. Both these numbers are expected to increase as producers ramp up drilling to maintain and increase production

in existing tight oil plays, develop new plays and begin drilling shale gas resources as prices improve.

Then there are the materials needed to fracture stimulate wells. The current industry focus is on drilling tight oil wells, which requires significant materials. The average Cardium well in central Alberta uses 20–30 tonnes of sand per fracturing stage, with 15–20 stages the norm per well.

But the amount of material used in fracturing shale gas wells is of a different order. Massive fracturing jobs in plays like the Horn River use as much as 300 tonnes of sand and proppant per stage, with as many as 25 stages per well. In the Haynesville shale gas play in the United States, it can take as many as 750 loads of water and 500 trailer loads of sand and proppant to complete a well.

For this reason, Mullen believes the arrival of liquefied natural gas (LNG) export terminals on the west coast will drive growth in oilfield hauling in the future as producers drill up tight and shale gas plays to supply the terminals.

“We think that is a game changer for the drilling industry and for the western Canadian economy,” he said, adding Mullen Group’s trucking and logistics and drilling operations are poised to benefit tremendously from growth in the LNG market. “On all fronts I think we can benefit, and it’ll just take us to new levels, in my opinion, as this unfolds over time.”

OIL & GAS INQUIRER • OCTOBER 2013

43

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Business

Intelligence Lack of money hurting resource play developers

By James Mahony

Resource play developers in western Canada have much on their plate these

“You’re just not going to raise that kind of money in Calgary today,” he said

days, but the scarcity of investment capital is a topic that keeps coming up

later. “There might be half a dozen management teams that can raise it, but for

during industry discussions.

the average engineer or geologist trying to get money, you’re just not going to

In days when capital was more abundant, Calgary-based start-ups could

raise that here.”

quickly raise $5 million to $10 million without going abroad, one executive

Instead, some Calgary producers, including Anterra, have tapped capital

recalled recently. The message at the Tight Oil Canada conference in Calgary

from China. “We’re not the only ones,” he said. “I think a lot of the capital for

late this summer, however, was that much more cash is needed in today’s

resource plays in Canada is going to come from Asia.”

maturing Western Canadian Sedimentary Basin, and the money is only getting harder to find.

For one junior that set up shop in Calgary two years ago, that proved only

Another speaker tied the current scarcity of capital to supply costs in western Canada’s emerging tight oil and shale gas plays, including the Montney, Muskwa (Horn River) and Deep Basin plays, among others.

too true. According to president and chief executive officer Howard Anderson,

Of the key metrics investors analyze before putting up capital, James

his team at Tuzo Energy Corporation had just tied up a farm-in near Willesden

Reimer, exploration vice-president at Painted Pony Petroleum Ltd., said calcu-

Green, in west-central Alberta, and was all set to drill. The only problem was a

lating the full cost of supply—gas or oil—dominates the equation. In the final

lack of capital.

analysis, project efficiency determines supply cost, and only the most efficient

“We were pitching for our first tranche of capital for a multi-well horizontal drilling program in the Second White Specks, around Calgary,” he told the con-

companies proceed. Faced with a range of possible investments, “capital providers become fussy,” he said.

ference, hosted by Canadian Business Conferences Limited. Early on, he noted

In former days, western Canada’s oil and gas landscape was different, charac-

the enthusiasm of younger staff at investment firms around town, while older

terized by abundant capital chasing fewer quality projects, while asset diversity

and greyer senior executives were more reserved. In the end, the ultimate

was a common goal. Today, the balance has shifted: there’s an abundance of

response was much the same.

projects, with capital migrating only to the most efficient players, and asset

“You guys have done your homework, and it’s great. It looks terrific,” he recalled being told. “We’re glad to see you’re pursuing this play. It really needs to be done, but come back and see us after you’ve proved it up.”

That response, according to Anderson, was not only frequent in Calgary, it was “the universal response.”

In part, he attributes that outcome to a choice his team made early on to focus their efforts on a less-favoured formation, the Second White Specks (SWS), which Anderson acknowledged has a somewhat “checkered reputation” among Calgary geologists, many of whom consider it troublesome.

“There is a prejudice against the Second White Specks, and popular opinion holds there are only one or two good SWS wells in Alberta. That’s not really true, but nevertheless, that’s the reputation of this play,” he said. When the company turned to the United States, as it eventually did, it got a different reception.

diversity is no longer a key goal.

Having analyzed supply in several tight oil and shale gas plays, Reimer said costs typically shake out as a J-curve. At the outset, progress on plays is rapid, as producers learn what works, and costs decline initially. How long the declining-cost leg lasts, however, depends on the play and cost profile of each producer, he said. In any case, after declining initially, costs typically start to rise and continue to do so over time.

On plays driven by horizontal, multistage wells, efficiency tends to be driven by more stages per well and more wells per pad, he said, noting more efficient producers tend to focus on one play or a few plays in a given area. As for inefficiencies that push up supply costs, Reimer’s list was a long one.

At the top of the list were producing zones that were too thin, wells that were too short (or too long), single-well batteries and water or emulsion

Three days before Christmas, in 2011, Tuzo landed private-equity funding

having to be trucked to well sites. The list, which was extensive, also included

from Denver-based SFC Energy Partners, which agreed to put up $50 million

drilling programs with too few wells, hard-to-frac zones, and “gourmet” and

over the next two years. According to Anderson, the people at SFC expressed

slickwater fracs.

surprise that no one in Canada would bite the bullet.

Other conference speakers also highlighted the gap between what teams needed to fund a start-up in the “old” days and what they need today. Owen

When it comes to opening up reservoirs that will serve liquefied natural gas (LNG) export markets from Canada’s west coast, Reimer said getting a grip on supply cost is key.

Pinnell, chairman of Anterra Energy Inc., noted that an ARC Financial Corp.

“We know we can get our costs down on a number of plays, [and] we know we

executive recently estimated today’s oil and gas start-ups need $200 million to

can liquefy, ship and deliver that gas, and beat the current costs of producing

$300 million to fund resource plays.

LNG in other parts of the world. That’s one of the key drivers of the LNG phe-

“That’s a huge contrast to financing that was required even five years ago,” Pinnell said.

nomena that’s currently underway,” he said, noting there were, at last count, about 12 LNG proposals out in Canada.

OIL & GAS INQUIRER • OCTOBER 2013

45

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