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EBITDA and the Value of Oilfield Services Companies.

Knowing this important number helps owners make better business decisions.

David Yager, Oilfield Services National Leader

For companies in the Oilfield Services Sector (“OFS”), optimal financial flexibility is essential in order to ride out the cyclical rollercoaster that characterizes this industry. Whether it’s growth, sale, mergers, acquisitions, bank debt or equity financing driving the transaction, in all of these cases, the EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) calculation is king.

“EBITDA is one of the primary valuation tools for determining the financial capacity of a business and is required when selling a business or when seeking financing,” explains David Yager, National Leader of MNP’s Oilfield Services practice. “It’s the starting point for placing a value on your operation.”

The EBITDA calculation tells people the amount of cash generated by business operations. All interest payments, tax, depreciation and amortization entries in the income statement are added back to bottom-line net income, enabling the comparison of the financial performance of different businesses.

“The ultimate value of a business is based on free cash and EBITDA is where you start. Ultimately, they want to know how much free cash the business will spin off for expansion and capital servicing along with how much debt it can afford,” explains Yager.

But EBITDA is considered a non-GAAP financial metric, so it doesn’t appear on most financial statements. It must be calculated manually, which requires a level of financial knowledge and analysis that many owners of private OFS businesses don’t possess or don’t have the time or inclination to learn.

This is in stark contrast to publicly-traded OFS companies. Their finance department routinely calculates EBITDA and states it in

supporting documents for their boards, management, investors and debt and equity capital providers. .

“That’s where MNP is different,” says Yager. “We’ve recognized EBITDA as a key OFS business valuation metric and put it in the financial statements so it’s right there when you or capital providers are considering an opportunity, investment or decision.”

However, EBITDA is not the only factor in determining value. Aspects such as whether the business is growing, the age of key assets, history of earnings or technological risk are also considerations.

But EBITDA is a key valuator in determining how much a potential acquirer can pay for a company, the risk of a lending decision, how much capital it can invest on expansion and whether or not it has the capacity to acquire one or more of its competitors.

Public OFS companies are usually valued at a premium because of liquidity (the ability to sell your investment tomorrow) and their ability to raise capital for growth by issuing treasury shares. The first step for private companies to create a similar competitive dynamic is to provide financial information that clearly and simply displays their financial performance on the same terms as their public competitors.

As Yager points out, EBITDA is the starting point. Having it right there on your income statement gives a business owner improved financial flexibility moving forward.

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

CONTENTS

JANUARY/FEBRUARY.

in the news

13

Conversions to dividend-paying corporations growing

regional news

17

27

British Columbia

Encana exits Kitimat LNG group

Northeastern Alberta

39

Southern Alberta

Smaller is better, say experts about

Federal cabinet rejects Cenovus Suffield

oilsands projects

shallow gas development

Baytex to spend $520 million in

33

43

2013, with Peace River oilsands a

Encana, PetroChina, partner in Duvernay

23

Northwestern Alberta

Central Alberta

major target

Saskatchewan

Crescent Point plans $1.35-billion capital budget

tech news

47

Cenovus submitting new rig technology to COSIA

features

Cover Feature

50 54 59 65 Good to the last drop

Taking shape

Last man standing

Turning on the switch

Enhanced oil recovery schemes aim to pull billions of barrels of trapped oil out of the ground

Pieces of CO2 enhanced oil recovery industry puzzle coming together in Alberta

Liquids-rich, highdeliverability wells keep natural gas drilling alive in northwestern Alberta

Early-stage oil developments promise long-term opportunity in northwestern Alberta

business intelligence Getting resource estimates right

every issue

10 Stats at a Glance 70 Political Cartoon

On the Cover EOR promises another generation of oil development in the WCSB Cover design by: Peter Markiw Straw illustration by: pialhovik@istockphoto.com

OIL&GAS January/February 2013 ~ $6.00

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NEW LOOK!

last drop Enhanced oil recovery schemes aim to pull billions of barrels of trapped oil out of the ground

Plus: Unconventional resource plays keep northwest Alberta industry in expansion mode

PM40069240

69

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

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Editor’s Note Vol. 25 No. 1

Vol. 24 No. 9

EDITORIAL EDITOR

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

Gross incompetence

Jim Bentein, Lynda Harrison, Richard Macedo, James Mahony, Pat Roche, Elsie Ross CONTRIBUTING PHOTOGRAPHER

Joey Podlubny

EDITORIAL ASSISTANCE MANAGER

Samantha Sterling | ssterling@junewarren-nickles.com EDITORIAL ASSISTANCE

Laura Blackwood, Tracey Comeau, Marisa Sawchuk, Matthew Stepanic CREATIVE PRINT, PREPRESS & PRODUCTION MANAGER

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

Cathlene Ozubko GRAPHIC DESIGNER

Peter Markiw

CREATIVE SERVICES

Christina Borowiecki production@junewarren-nickles.com SALES SALES MANAGER—ADVERTISING

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

Diana Signorile SALES

Nick Drinkwater, Sammy Isawode, Mike Ivanik, Nicole Kiefuik, David Ng, Tony Poblete, Sheri Starko For advertising inquiries please contact adrequests@junewarren-nickles.com AD TRAFFIC COORDINATOR—MAGAZINES

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

Bill Whitelaw | bwhitelaw@junewarren-nickles.com VICE-PRESIDENT

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

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

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

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

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SUBSCRIPTIONS Subscription Rate

$75 million a day.

That’s how much the Alberta government estimates it is losing every day due to a lack of pipeline carry-away capacity for its growing bitumen and oil production.

To put that in perspective, it equals building a big new elementary school every day. In a month, almost two Calgary south hospitals could be built.

But none of these are happening.

Instead, Alberta is taking a discount of up to $40 per barrel to get rid of some blends of crude because it lacks connections to a market. In total, it is costing industry and government as much as $40 billion annually, according to the province.

How did this happen?

The blame belongs to the Alberta Conservatives under the leadership of Ed Stelmach.

Both industry and government have been predicting a massive increase in production from the oilsands for more than a decade.

Yet no action was taken to find outlets for the growing supplies. There was total complacency, with the view that the United States would take all we could produce.

Projects were approved without any focus on ensuring the people of Alberta received the maximum price for their oil.

So here we sit, selling a non-renewable resource for 33 per cent under worldmarket value.

Premier Redford should be focused on this issue 24-7 until it is resolved. But instead, she is forced to deal with the budgetary effects of the revenue shortfall.

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

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.

Darrell Stonehouse

Editor dstonehouse@junewarren-nickles.com

Subscription Inquiries

Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com

What about the federal government, which is in charge of approving pipelines that cross provincial or international borders?

They have been talking a good game, streamlining approval processes and making speeches about the importance of the new lines. But talk is cheap, and the past record of the Harper Conservatives when it comes to dealing with oil and gas issues has been less than stellar. Remember the energy services trust tax fiasco?

The truth is if Harper wore red and his last name was Trudeau, the industry would have the torches and pitchforks out for the way his government has dealt with it. The current price discount is worse than Trudeau’s proposed made-in-Canada prices of the early 1980s.

That’s this month’s rant.

On a brighter note, welcome to the new and improved Oil & Gas Inquirer. This year marks the 25th anniversary of our magazine and a quarter century of continuous improvement. To celebrate, we have redesigned the publication to make it more reader and advertiser friendly.

Over the next few months, you will see more changes as we update our regional news sections to bring more quality information to you, our readers. A new and improved website is also coming, so stay tuned.

All this is made possible by our advertisers, who foot the bills that allow us to bring you the news. Thank you for your support over the last 25 years, through the ups and downs of the industry, and we will do our best to keep you happy in the future.

N E XT I S S U E March 2013 A review of how producers are adapting technologies to capture more heavy oil resources. Plus a trip to the oilfields of southern Alberta.

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

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

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

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

9

FAST NUMBERS

$.

$.

Brent crude price per barrel on January 10, in US dollars.

West Texas Intermediate price per barrel on January 10, in US dollars.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

M O NTH

OIL

GAS

OTHER

MONTH

OIL

GAS

D RY

SERVICE

T O TA L 1,489

Dec 2011







0

Dec 2011









Jan 2012







31

Jan 2012









655

Feb 2012







1

Feb 2012









1,153

Mar 2012







1

Mar 2012









1,275

Apr 2012







1

Apr 2012









988









449

Jun 2012









Jun 2012

Jul 2012









Jul 2012









873

Aug 2012









986

Aug 2012







1

Sep 2012









Sep 2012









908

Oct 2012







1

Oct 2012

,







1,269

Nov 2012







0

Nov 2012









1,250

Dec 2012







3

Dec 2012









1,054

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

Dec 2011

58

796

Dec 2011







3

Jan 2012

53

53

Jan 2012







10

Feb 2012

66

119

Feb 2012







3

Mar 2012

39

158

Apr 2012

Mar 2012









86

244

Jun 2012

13

334

Apr 2012







1

Jun 2012







1

Jul 2012

57

401

Aug 2012

53

454

Sep 2012

11

465

Oct 2012

28

493

Nov 2012

78

571

Dec 2012

65

636

*From year-to-date * from year to date

10

T O TA L

J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

Jul 2012









Aug 2012







30

Sep 2012







310

Oct 2012







0

Nov 2012







3

Dec 2012







31

STATS

AT A

GLANCE

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, January 11, 2013 Source: Rig Locator

Alberta, January 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

Dec 1

GAS WELLS

Dec 11

Dec 1

Dec 11





1

%

Northwestern Alberta









British Columbia







%

Northeastern Alberta









Manitoba







%

Central Alberta









Saskatchewan





1

67%

Southern Alberta



95







1

1

3%

TOTAL

3



110



WC TOTALS

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, January 11, 2013 Source: Rig Locator

Alberta, January 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

Dec 1

Dec 11

BITUMEN WELLS Dec 1

Dec 11







%

Northwestern Alberta















%

Northeastern Alberta













1

%

Central Alberta









Saskatchewan





201

63%

Southern Alberta









WC TOTALS



3

3

0%

TOTAL

1



13



British Columbia

Manitoba

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

11

seizing

industrial opportunity

For business expansion or relocation information contact Economic Development at:

780.992.6231 or visit www.fortsask.ca

IN THE

NEWS Issues affecting Canada’s E&P industry

Conversions to dividend-paying corporations growing

By Pat Roche

Photo: Joey Podlubny

Expect more exploration and production firms in western Canada to convert into dividend-paying intermediate-size producers—a trend that will create winners and losers, says an analyst.

“It’s here today, but it’s coming further next year in a big way,” predicts Robert Cooper of Haywood Securities Inc. A number of companies moved to the dividend-pay ing model in 2012.

Pinecrest Energy Inc. and Spartan Oil Corp. announced in November they were merging to create a dividend-paying light oil producer. Whitecap Resources Inc. announced plans to become an intermediate-size light oil producer that would pay dividends as well. In October, Renegade Petroleum Ltd. said it would pay $405 million to buy light oil assets producing 3,600 barrels of oil equivalent

per day in southeastern Saskatchewan from an unnamed senior producer, and start paying dividends.

In January 2012, Twin Butte Energy Ltd. and Emerge Oil & Gas Inc. agreed to merge into a single dividend-paying heavy oil–weighted corporation focused on acquisitions.

Driving this trend is the inability of smaller producers to raise money on today’s poor equity markets, followed by investors’ desire for dividends, said Cooper.

“Don’t underestimate the fact that the street wants yield,” Cooper told a CFA Society luncheon held in conjunction with the Explorers and Producers Association of Canada’s Oil & Gas Investor Showcase.

Cooper said the yearning for yield goes back to 2006 when the federal government ended the era of income-

With investment markets turning frigid, many intermediate producers are upping dividends to attract investors.

paying trusts by eliminating their special tax status.

Companies producing 10,000–11,000 barrels equivalent per day were all trust candidates. With that door closed and without capital-market support, the only option for growth is consolidation.

Meanwhile, investors are looking for less risk, reduced volatility and an income stream.

“And that’s been the theme. I don’t think that’s going to stop,” said Cooper.

Within the next year there may be four or five more such announcements, he said, adding that some privately held producers and public companies the size of Surge Energy Inc. and Legacy Oil + Gas Inc. are also potential candidates.

“The problem,” he said, “is it’s not that easy.”

So what does a sustainable dividendpaying intermediate-size oil and gas producer look like?

“Obviously you need the appropriate commodity, and today that’s oil,” Cooper said. But the challenge is there aren’t enough non-oilsands oil assets available in western Canada to permit extensive growth.

“The reality is it’s mostly a gassy basin,” he said, adding that current gas prices don’t support any income, let alone payouts to shareholders.

Secondly, a sustainable dividendpaying producer needs appropriate assets.

“Lots of companies, I think, are striving for this model,” Cooper said. “I think a few quality ones will actually get there.”

“The decline rate…is probably the key determinant, all else [being] equal, in a sustainable yield model,” he said.

Here Cooper distinguished between producers that are paying a small dividend

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

13

In The News

Pressure pumpers facing rocky road, says TD Bank

By James Mahony

“ Once you cut your dividend, you have a long way to come back.” ­— Robert Cooper, oil and gas analyst, Haywood Securities Inc.

but are still mostly growth oriented, and those paying a much larger dividend mostly to attract retail investors who want income.

“And so you could basically categorize those sort of three per cent dividend yields separately from companies paying out six, seven, eight per cent of their stock price who are basically foregoing growth at that point, paying out your cash as income,” he said. “But the key determinant of sustainability is really your decline rate. And how do you backstop your decline rate? Ideally, if there only were more Dixonvilles or Valhallas out there, that would be ideal.

Nice waterflood, nice steady low decline to backstop all those high-decline new drills that come online.”

A sustainable, dividend-paying producer’s assets also need predictability and repeatability, said Cooper, “because once you go dividend, you cannot go back. It’s a ruthless market for those that end up cutting their dividend.”

He listed capital ef f icienc y— t he amount of capital spent to bring on new production—as the third prerequisite.

Companies probably should be aiming for roughly $25,000 per flowing barrel, but can probably get away with the low $30,000 range, he said. “It really depends.

But you cannot be wasting capital if you expect to be paying dividends.”

The fourth requirement is risk management. Unlike a junior focused exclusively on growth, the dividend-paying producer needs a strong hedge book and “a different management attitude where growth isn’t the priority. It’s got to be maintenance of the dividend,” Cooper said. “As I said, once you cut your dividend, you have a long way to come back.”

14

The year 2012 marked a turning point for pressure pumping companies working in the United States as supply of horsepower outstripped demand, Scott Treadwell, vice-president and equity analyst for TD Bank Group, told a group of colleagues in Calgary before Christmas.

Treadwel l of fered adv ice to oi lfield service companies, some of which have weathered a rough ride in the U.S. market, especially pressure-pumping compa n ie s work i ng Nor t h Da kot a’s Bakken play, over the past year, he said.

He ac k nowle dg e d t he sh a k e out that has occurred over the past several mont hs, noting substantial pumping capacity has been taken out of service in the U.S. market.

“If you focus on supply and demand, there’s been a very strong correction,” he said, also suggesting ser vice companies working that market have not been quick to learn their lessons. “As much as pressure-pumping companies overbuild—they were too enthusiastic on the way up—I can almost guarantee you that they’re too conservative on the way down. They’ll retire too much equipment, lay off too many workers and underestimate the rebound in demand that happens at some point.”

Looking at the broader U.S. pressurepumping picture, he said the big service companies’ pumping fleets, Schlumberger Limited and Halliburton in particular, really started to be built up during the Barnett shale rush in 2004, with one to two million hydraulic horsepower (HHP) being added every year for a while.

“By a nd la rge, t hat equ ipment is now irrelevant,” Treadwell said. “The equipment t hat wa s pu mpi ng i n t he Barnett shale 10 years ago was probably 1,500 HHP. It’s probably a Triplex pump that can’t stand working 24 hours a day. Putting that into an Eagle Ford– ty pe operation is a recipe for disaster.

You could probably get away with it in t he Per mian shor t-ter m, but 24 -hour operations don’t work well w it h t hat equipment.”

As the U.S. market evolves, a structural gap is developing, as many of the

J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

pumping units being parked today represent older equipment from that era, he said. “Really, it’s not coming back. Unless there’s a massive resurgence in conventional fracturing demand—in conventional limestones and sandstones—that equipment is by and large done.”

Treadwell reiterated t hat he does not foresee a recover y any time soon, while at the same time calling the claim t hat t he pressure-pumping market is over 20 per cent oversupplied “wildly pessimistic.”

In the U.S. market, “the supply correction is under way,” and “it appears that pricing is starting to stabilize. The deceleration of pricing is certainly slowing,” he said.

The picture for Canadian oilfield service companies is brighter, however. Since the end of the third quarter, Treadwell said Canadian completions are up about 30 per cent from last year, although his estimate represented only the first half of the current quarter.

“That’s what the pumpers are seeing in Canada. There’s obv iously pricing margin dynamics outside of that, but the activity level is substantially higher than we saw in the third quarter. From my point of view, whether your margins are contracting or your pricing is moving sideways or down, that ’s obviously a big driver, but if your activity levels are moving up sequentially, fundamentally, that’s a good thing.”

What’s driving activity in the oilfield service sector? For one thing, land sales, he said, noting that last year he and other analysts based their outlooks for higher capital spending on drilling due to strong land sales in western Canada.

At the time, he believed the “capital pie was going to stay roughly the same, but given the last two years of massive land sales, we saw there was no need to go buying land,” he said. “Land sales were going to dry up. That’s been true, but the pie has shrunk. In western Canada’s key resources plays, land positions are well entrenched.”

In t he cur rent market, producers are taking longer to develop resource

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with demand.

plays, Treadwell said. “They’re taking a lot longer to go from science to development, and while we expect over time that this acquired land needs to be developed—at least a good chunk of it— you’re going to see more efficient use of drilling assets and drilling dollars to explore and develop that land.”

Given the consolidation now underway in Canada’s oilfield service market, companies who plan to grow over time will need to build size. “Scale is the only way to do that,” he said.

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BRITISH COLUMBIA WELL ACTIVITY DEC/11

DEC/12

Wells licensed





DEC/11

DEC/12

Wells spudded





DEC/11

DEC/12





Rigs released

▼

▼

British Columbia

▼

Source: Daily Oil Bulletin

Encana exits Kitimat LNG group

Image: Apache Corp.

Encana Corporation is selling its 30 per cent stake in a proposed liquefied natural gas (LNG) export terminal project in Kitimat, B.C., to Chevron Canada Limited for an undisclosed price.

Included in the sale are Encana’s 30 per cent interest in the associated Pacific Trail Pipeline, as well as about 32,500 acres of undeveloped land in the Horn River Basin of northeastern British Columbia and the assumption of Encana’s take-or-pay processing commitments for the first phase of the Cabin gas plant.

The sale is subject to regulator y approvals and post-closing adjustments, but is expected to take place in the first quarter of 2013, said Encana spokesperson Jay Averill.

Encana is selling a small portion— less than 25 per cent—of its Horn River holdings, Averill said.

Chev ron is also buy ing out EOG Resources, Inc.’s 30 per cent share at an undisclosed price.

Chev ron Canada, a subsidiar y of S a n R a mon , C a l i f.- b a s e d C he v r on Corporation, and Apache Canada Ltd. each will become a 50 per cent owner of the Kitimat LNG plant, the Pacific Trail Pipeline and 644,000 gross undeveloped acres in the Horn River and Liard basins.

Chevron Canada will operate the LNG plant and the pipeline, while Apache Canada will operate the upstream assets.

Current plans call for two liquefaction trains, each with expected capacity of five million tons of LNG per year, or about 750 million cubic feet of gas per day.

K itimat has received all sig nif icant environmental approvals and a 20-year export licence from the federal government.

Encana joined the Kitimat LNG project with partners Apache Canada and EOG in March 2011.

The sale of Encana’s interest in the proposed Kitimat LNG export facility is consistent with the company choosing to

Artist’s rendering of the proposed Kitimat LNG export terminal.

focus on its core business, Encana said in a release, adding that it also reduces the company’s future capital commitments.

The proceeds from the transaction will help to strengthen the balance sheet and provide further financial flexibility to fund capital programs and develop key and emerging resource plays, it said.

The deal gives Chevron a 50 per cent operating interest in the Kitimat LNG project and proposed Pacifi c Trail Pipeline, and a 50 per cent interest in approximately 644,000 acres of petroleum and natural gas rights in the Horn River and Liard basins in British Columbia.

750million Cubic feet of gas per day. Expected capacity of each LNG train.

“The Kitimat LNG development is an attractive opportunity that is aligned with existing strategies and will drive additional long-term production growth a nd s h a r e holde r r e t u r n s ,” G e or g e Kirkland, vice-chairman of Chevron, said in a news release.

Chev ron has existing L NG plants in Australia and is developing plants in A ngola, Nigeria, China, Vietnam, Thailand and Venezuela.

“This investment grows our global LNG portfolio and builds upon our LNG construction, operations and marketing capabilities. It is ideally situated to meet rapidly growing demand for reliable, secure and cleaner-burning fuels in Asia, which are projected to approximately double from current levels by 2025.”

The proposed two-train Kitimat LNG Project, currently progressing through the front-end engineering and design

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

17

British Columbia

phase, has a National Energ y Board licence to export 10 million tons per year of LNG. The project is slated to begin shipping gas to Asian markets by 2017.

Chevron Canada will acquire approximately 110,000 net acres in the Horn R iver Basin f rom Enca na, EOG a nd Apache, and approximately 212,000 net acres in the Liard Basin from Apache.

“This agreement is a milestone for two principal reasons: Chevron is the premier LNG developer in the world today with long-standing relationships in key Asian markets, and the new structure will enable Apache to unlock the tremendous potential at Liard, one of the most prolific shale gas basins in North A merica,” G. Steven Farris, Apache’s chairman and chief executive officer, said in a news release. “At Liard and Horn River, we have built substantial positions in two of the most prolific shale gas plays in North America, with more than 50 trillion cubic feet of resource potential,” said Farris.

— DAILY OIL BULLETIN

18

Artek Exploration completes 2012 horizontal drilling program at Inga Artek Exploration Ltd. said it has successfully drilled and completed its sixth and seventh horizontal wells of a 2012 seven-horizontalwell program (60 per cent working interest) at A13-33-88-23W6 at Inga, B.C. The wells represent an extension to the southern end of Artek’s Doig natural gas and condensate trend and at A13-3-88-23W6.

The results of the respective 114- and 87-hour well tests were consistent with average test results achieved by the company at Inga to date as previously disclosed. Immediately following the test periods, the wells were producing from the Doig in-line at an average initial rate per well of approximately 4.5 million cubic feet per day of natural gas and 946 barrels per day of liquids based on field estimates over a 24-hour period.

As a result of the two new wells coming on production, Artek is managing individual well production through its facility with some of its older wells temporarily restricted

J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

and, therefore, additional completion or workover activity that could result in additional volumes will be postponed until 2013.

Consistent with investment in facilities in parallel with its drilling activity during 2012, Artek will continue to incrementally

Artek production averaged over 4,000 barrels equivalent per day during the second week of December. expand the capacity at its operated facility during this year as necessary.

At Leduc-Woodbend in Alberta, the company has brought on the four (1.6 net) wells from its September/October 2012 development program. Production volumes for the property were averaging between 650 and 690 barrels per day (97 per cent crude oil) over November, up from approximately

Photo: Joey Podlubny

British Columbia

370 and 400 barrels per day during the summer, and ahead of management’s initial expectations.

Artek now operates the property and plans to drill additional wells in 2013 and increase water injection into the oil property, which has been under waterflood since 2001.

Including the incremental volumes from the Inga and Leduc-Woodbend, Artek production averaged over 4,000 barrels equivalent per day during the second week of December based on field estimates (with some wells currently restricted at its facility at Inga), achieving its previously announced 2012 exit-production guidance of 4,000 barrels equivalent per day.

During early December, the company estimated it had averaged between 43 per cent and 45 per cent oil and natural gas liquids of which approximately 87 per cent to 90 per cent is oil and condensate.

The company was planning to provide details of its planned operations and guidance for 2013 in late January.

— DAILY OIL BULLETIN

B.C. December sale draws $30.57 million; hectares sold lowest on record

In 2012, B.C. had the lowest bonus bids it has seen since 1998.

British Columbia closed its 2012 land-sale schedule by attracting $30.57 million in bonus bids at the December disposition of Crown oil and gas rights—its secondhighest bonus total at a single sale in 2012.

For last year, the province—which has mainly natural gas production and lit t le oi l out put— col lec ted $139.26 million in bonus revenue on 136,521

hectares at an average price of $1,020.08.

That’s the lowest calendar-year bonus total since 1998, when British Columbia attracted $96.34 million in revenue. It’s also the lowest in terms of hectares disposed, according to statistics dating back to 1978.

Although 2012 represents the lowest number of hectares disposed in B.C.

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19

British Columbia

history, the average price per hectare is much higher than those of earlier years, said a B.C. government spokesperson.

“The disposition of Crown petroleum and natural gas rights began in the 1950s. The dispositions have always involved a competitive public-tender bidding process.

“The statistical breakdown in monthly/ yearly/fiscal formats started in 1978.

Records are available as far back as the 1950s, but they differ from the presentation used today and are not stored electronically at this time.”

The final sale of 2012 saw 30,393 hectares changing hands—the highest total at a single auction that year—at an average of $1,005.82.

Highlights of the sale included a bonus high bid of $8.67 million by Maverick Land Consultants 2012 Ltd. for a 5,329-hectare licence in the Sojer area, about 130 kilometres north of Hudson’s Hope. The broker picked up the rights to three tracts, which included several units, at 94-H-04.

Meanwhile, Charter Land Services Inc. tendered a bonus of $5.63 million for a 5,579-hectare lease in the Laprise

Creek West area, about 150 kilometres north of Hudson’s Hope. The broker paid an average of $1,009.37 for the rights to three tracts, which included several units, at 94-G-08.

In terms of these two parcels, Brad Hayes, president of Petrel Robertson Consulting Ltd., said that most of the lands are posted for deeper rights below the Baldonnel or Charlie Lake.

“There are also some smaller parcels posted in the area that attracted healthy per-hectare bids,” he said. “It appears very likely that the main target is the Montney, as the fairway seen to be prospective has been creeping eastward and northward from the original play areas. Liquids and oil will likely be more abundant in up-dip areas, particularly in 94-H-04, than in some of the deeper parts of the fairway.”

British Columbia still shows good perhectare bids, he added, because there is still long-term value in the main drivers, which are the Montney and other unconventional reservoir fairways.

— DAILY OIL BULLETIN

PETRONAS, Progress move to next phase of LNG export project PETRONAS Carigali Canada Ltd. and Progress Energy Resources Corp. could make a final investment decision for a proposed LNG project in late 2014, with first exports in 2018.

If t he projec t—na med Pac i f ic Northwest LNG—proceeds, the estimated investment in the LNG export facility is expected to be between $9 billion and $11 billion, depending on the fi nal project scope, the partners said. The construction phase would result in up to 3,500 direct jobs and the long-term operations of the facility would result in 200–300 direct jobs.

The throughput of natural gas at the LNG export facility is expected to increase by approximately 60 per cent to six million

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British Columbia

A final investment decision on the LNG facility for the West Coast is expected to come in late 2014.

tonnes per annum per train, which will also result in concurrent enhancements to the productivity and efficiency of related upstream activities.

The companies said that the proposed LNG export facility is now moving into the next phase of engineering.

The project’s detailed feasibility study for a LNG export facility on Lelu Island in the District of Port Edward has been successfully completed and the project is moving into the pre–front end engineering design (pre-FEED) phase. The pre-FEED phase will be done to provide certainty around project scope and a further understanding of construction timelines, costs and labour-force requirements.

The next phase of engineering work will include the submission of a project description to Canadian regulators in early 2013, Michael Culbert, president and chief executive officer of Progress, said in a news release.

“In addition, we are pleased to have off icially named our project Pacif ic Northwest LNG and will continue to move

the project forward at an aggressive pace,” he added.

The project will include two trains, or liquefaction plants, when initially constructed.

Planning will include the ability to expand with the addition of a third train in the future. The LNG throughput is currently designed for about 3.8 million tonnes per annum per train based on the LNG export joint venture that was announced between the two companies in 2011.

Overall, Pacific Northwest LNG represents significant revenue and royalties to the provincial and federal governments, and the opportunity for economic benefits to the local First Nations and communities, the companies said.

A final investment decision for the project continues to be expected in late 2014, followed by the first LNG exports in 2018.

Pacific Northwest LNG will be opening its Vancouver office in early 2013 and will be growing its project team.

— DAILY OIL BULLETIN

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NORTHWESTERN ALBERTA WELL ACTIVITY DEC/11

DEC/12

Wells licensed





DEC/11

DEC/12

Wells spudded





DEC/11

Rigs released



▼

▼

DEC/12



▼

Source: Daily Oil Bulletin

N.W. Northwestern Alberta

Baytex to spend $520 million in 2013, with Peace River oilsands a major target

Photo: Joey Podlubny

Baytex Energy Corp. has set its 2013 exploration and development capital budget at $520 million.

The company plans to spend $430 million on its conventional oil and gas operations.

That outlay is designed to generate an average production rate of 56,000–58,000 barrels equivalent per day, an increase from the current guidance range of 53,500–54,500 barrels per day for 2012.

An additional $90 million of capital will be directed toward two thermal-enhanced oil recovery projects, as Baytex positions for growth in 2014 and beyond.

The 2013 budget continues the company’s focus on oil-weighted production growth, while also providing funding for projects that will allow Baytex to moderate its long-term corporate decline rates and support its abilit y to continue to

execute the growth-and-income business model.

“Based on the mid-point of the production guidance ranges for 2012 and 2013, our 2013 plan reflects production growth rates of eight per cent for oil and natural gas liquids volumes and six per cent for oil equivalent volumes,” the company said in a press release. “Our 2013 production mix is forecast to be approximately 89 per cent liquids [75 per cent heavy oil and 14 per cent light oil and natural gas liquids] and 11 per cent natural gas, based on a 6:1 natural-gas-tooil equivalency.”

Approximately one-half of the 2013 capital budget will be invested in conventional heavy oil operations at Peace River, Alta., and Lloydminster, Alta. The company plans to drill 37 horizontal multilateral wells in its Peace River region.

Imperial Oil’s Cold Lake development. Baytex plans to use cyclic steam at Peace River like Imperial uses at Cold Lake.

“Our multilateral drilling program at Peace River continues to be one of the highest rate of return projects in the oil and gas industry,” Baytex said.

At Lloydminster, the company plans to drill 108 wells, approximately evenly split between vertical wells and horizontal wells.

This area is characterized by stacked pay that has led to successful exploitation of multiple horizons.

Baytex has allocated approximately 17 per cent of its 2013 capital budget toward two thermal-enhanced oil recovery projects.

“Once developed, thermal recovery projects provide a source of long-life, low-decline

37

wells

Number of mulitlaterals to be drilled at Peace River production, which will enhance our ability to continue our growth and income model over the long term. These two projects are expected to contribute to our growth profile in 2014 and beyond,” the company said.

At Cliffdale in the Peace River region, the 2013 capital budget includes funding for the drilling and facility construction of a second module of commercial thermal development.

The second thermal module is planned as a 15-well cyclic steam stimulation (CSS) project with development expected to begin in the first quarter of 2013.

Based on numerical reservoir modelling, Baytex anticipates a peak annual rate of approximately 2,000 barrels per day, which the company expects to occur in approximately year four of the development.

At Cold Lake in the Lloydminster region, the company said it will begin construction of its steam assisted gravity drainage (SAGD) pilot project. Expenditures will include lease and facility construction and the drilling of one SAGD well pair. The balance of the

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

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capital program will be directed primarily towards light oil development, with the single largest project being the Bakken/ Three Forks in North Dakota. The company’s 2013 development plan in North Dakota represents approximately 15 per cent of the 2013 capital budget, and will include the drilling of approximately 22 (9.3 net) wells.

Baytex plans to drill approximately 228 net wells in 2013, of which 187 will target crude oil, three will target natural gas and 38 will be stratigraphic and service wells.

The 2013 stratigraphic-and-service-well program will support multilateral drilling programs in future years, further delineate the company’s lands at Cliffdale for thermal development and enhance operating cost efficiency by expanding water disposal capacity near Baytex’s core producing assets.

The company said it expects to finance its 2013 capital budget and dividend with funds from operations and its existing credit capacity.

— DAILY OIL BULLETIN

Grande Prairie area selected for Encana, Ferus LNG facility Encana Corporation and Ferus LNG Inc., a North American leader in liquefied natural gas (LNG) fuelling solutions, are teaming up to build a 190,000-litre-per-day LNG production facility near Grande Prairie, Alta.

The facility, expected to be in operation by the end of next year, is strategically located in close proximity to high levels of energy industry activity in northwestern Alberta and northeastern British Columbia.

It is among the first in Canada designed to produce high-quality LNG fuel specifically for high-horsepower (HHP) engines used in drilling rigs, pressure-pumping services, and heavy-duty highway and off-road trucks. Other HHP applications for the LNG supply include rail, mining, and remote power generation.

To support the entire LNG supply chain, Encana and Ferus LNG have also designed and are in the process of building specialized mobile storage and dispensing equipment.

“LNG is quickly becoming the fuel of choice for HHP engines in both highway and off-road applications in North America,” Eric Marsh, Encana executive vice-president and senior vicepresident, USA division, said in a news release. ‘‘This project demonstrates the increasing viability of LNG as a fuel alternative for a wide range of industries,” he said. ‘‘With this new LNG plant, Encana and Ferus LNG are meeting a growing market demand by helping diesel consumers in northern and western Canada make the switch to cleanerburning natural gas to both save costs and reduce their emissions.”

The joint-venture project is unique in that it brings together two experienced

J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

12

$

million

Amount saved in fuel costs by Encana in 2011

and complementary parties who, in addition to enabling their business partners and customers to switch to LNG, have committed to using the fuel for their own internal consumption. In 2011 alone, Encana saved $12 million in fuel costs by using natural gas instead of diesel in drilling rigs and company trucks and was on track to exceed this figure in 2012.

“Ferus Inc. understands the economic and environmental benefits of using LNG as an alternative fuel, and as such, not only are we operating the fi rst two LNG tractors in Alberta, we plan to convert our entire truck fleet over the next fi ve years,” said Richard Brown, president and chief executive officer. “We are very pleased to be working with Encana to help develop the natural gas engine market by ensuring fuel supply and operating the necessary equipment to safely and reliably get the product to our customers’ site.”

— DAILY OIL BULLETIN

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NORTHEASTERN ALBERTA WELL ACTIVITY DEC/11

DEC/12

Wells licensed





DEC/11

DEC/12

Wells spudded





DEC/11

Rigs released



▼

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DEC/12

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Source: Daily Oil Bulletin

N.E.

Northeastern Alberta

Smaller is better, say experts about oilsands projects

By Lynda Harrison

Photo: Joey Podlubny

Keeping oilsands projects in the 40,000-barrel-per-day range makes cost management easier.

When it comes to building oilsands projects, smaller is better, and it’s best to involve suppliers early in the process, an industry gathering heard late last year.

While there can be economies of scale as plant sizes increase, there is also “a bit of a tipping point, a sweet spot” of about 40,000 barrels per day of production, says a mechanical engineer who has been building oilsands and power generation projects in Canada and abroad for more than 15 years.

There has been a history of cost escalations at projects larger than that, said Rick Koshman, vice-president of projects and thermal operations at Athabasca Oil Corporation.

“Certainly my personal experience is directly in line with this, that once you go above 1,500 people on site you lose your ability to maintain line of sight with the job, your control of it,” Koshman told a JuneWarren-Nickle’s Energy Group Speaker Series breakfast.

Before joining At habasca Oil, Koshman was the manager of thermal oilsands projects with Canadian Natural Resources Limited. Prior to that, he was PetroKazakhstan’s senior manager of projects, and Colt Engineering Corporation’s project engineer.

He has been involved with—and is sometimes the lead on—projects worth about $3.1 billion, and he has noticed a common thread throughout.

“Once you’re below that number it seems cost escalation history in Alberta is not nearly as bad as what people think,” he said. “Smaller projects have much better performance.”

That’s why Athabasca Oil’s projects— such as the proposed 80,000-barrel-perday Hangingstone—are being built in phases, said Koshman.

If approved, the first phase of the steam assisted gravity drainage project will be 12,000 barrels per day, and the

two subsequent phases are each slated to be 35,000 barrels per day.

While all three phases will be brought on stream over a period of four years (201418), once all phases are constructed they will operate as a single plant, offering flexibility, he said.

During construction, the projects will be able to share infrastructure such as roads, electrical power, utilities, camps, control rooms and pipe racks.

T he f irst phase of Hangingstone received regulatory approval earlier in 2012. Athabasca Oil plans to file regulatory applications for development of Hangingstone 2 and 3 this year.

Front-end engineering and design for Hangingstone was completed during the third quarter of 2012, and production will start in the fourth quarter of 2014. So far it is ahead of schedule, said Koshman.

Athabasca Oil developed a project procurement plan in the earliest cycle of the project, as early as the design basis memorandum (a detailed level of engineering), he said.

Having an early procurement plan enables his teams to not only effectively procure long-lead items but helps identify them early so they still have options, he said.

O t he r ke y pl a n n i ng do c u me nt s Athabasca Oil uses are the stage gate (sanctioning), project charter (a project execution plan that outlines everyone’s roles and responsibilities and identifies gaps early on) and a construction execution plan, similar to the procurement plan.

The riskiest time period for misalignment is when the project is in the field, when staffing is at its highest and the danger of cost escalation is at its peak—so Athabasca Oil removes as many man-hours from the field as possible, he said.

Athabasca Oil makes sure its engineering and procurement deliverables are following the construction schedule and

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

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Northeastern Alberta

ensures constructability is built into the design, he added.

“Being an engineer, I can say I’m sure I’ve designed things in the past that were not exactly constructible and it’s great when you have a construction manager or a construction supervisor sitting alongside with you to say, ‘Why don’t you do this, that or the other,’ and he corrects you early on,” said Koshman.

Being the prime contractor is also important to Athabasca Oil, he said.

He cautioned against “pulling the trigger” on major construction in the field before everything is ready. If engineering deliverables, materials and equipment are not on site and contractors aren’t ready, don’t mobilize and try to catch up with overtime or double shifts, for example.

“That ends up being more panic driven than schedule driven.”

Athabasca Oil researched the viability of having modules constructed in the United

States but found structural steel and transportation were more expensive and it is best avoided when shop space is available locally, he said.

When modules are built close to the construction site, familiar companies can be hired and that’s a big advantage when the relationship has been strong in the past.

There is also the benefit of being able to go to the site on a routine basis to monitor quality, said Koshman.

Cenovus’s oilsands spending plans flat

28

Cenovus’s Foster Creek operations. The plant is now producing 120,000 barrels per day.

day net in the coming year, a 60 per cent increase compared with forecast average 2012 production.

Start-up times at Christina Lake have been greatly improved due to production commencing in a higher-quality area of the reservoir, said Cenovus.

In addition, start-up times were enhanced by commercialization this year of the company’s accelerated start-up technology using steam dilation, which is among 140 technology development projects on which the company is working.

Cenovus said its Foster Creek facility demonstrated excellent operating performance in 2012, running near—and sometimes beyond—its plant design capacity of 120,000 barrels per day gross.

Expansion work at phases F, G and H at Foster Creek is now underway with added production capacity expected in 2014.

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Final partner approval of the first phase for the 130,000-barrels-per-daygross Narrows Lake project was just received. Foster Creek, Christina Lake and Narrows Lake are jointly owned with ConocoPhillips Canada.

Approximately $2 billion of the capital budget is dedicated to maintaining current operations and building already-approved oilsands expansions.

The remaining budget is discretionary capital focused on advancing oilsands projects through the regulatory process and increasing conventional oil production.

Capital investment at Christina Lake is anticipated to range between $570 million and $630 million in 2013.

The next expansion at Christina Lake, Phase E, is about 65 per cent complete and is now expected to begin producing in the third quarter of 2013 instead of the

Photo: Joey Podlubny

More than half of Cenovus Energy Inc.’s total 2013 capital investment of $3.2 billion to $3.6 billion—down one per cent from expected spending this year—is earmarked for the company’s oilsands assets.

Spending will focus on expansions at Foster Creek and Christina Lake, stratigraphic well drilling and the development of Narrows Lake.

Cenovus expects next year’s oil production to grow to between 180,000 and 196,000 barrels per day, up from this year’s expected output of 165,000 barrels per day, which is on track with its forecast.

“We anticipate 14 per cent oil growth in 2013, driven primarily by production additions at Christina Lake and Pelican Lake,” John Brannan, executive vice-president and chief operating officer, told a conference call held to announce the budget.

Guidance for this year puts capital spending at $3.3 billion to $3.4 billion.

“We anticipate taking substantial steps again next year toward achieving our longterm objective of increasing oil production threefold between 2012 and the end of 2021,” said Brian Ferguson, president and chief executive officer.

When Christina Lake’s Phase D — expected to start producing at full capacity during the second quarter of 2013—is fully operational, the project is forecast to have production capacity of 98,000 barrels per day gross.

An additional increase of 40,000barrels-per-day-gross production capacity is expected in the third quarter with the startup of Phase E a few months earlier than expected and within budget. Christina Lake oil production is expected to average between 47,000 and 52,000 barrels per

Northeastern Alberta

fourth quarter while Phase F construction is advancing.

Engineering and design work is underway for Christina Lake Phase G. Cenovus plans to submit a regulatory application in 2013 for a proposed Phase H expansion at Christina Lake.

Total production capacity is expected to reach 288,000 barrels per day by the end of 2019, and as high as 300,000 barrels per day with optimization.

Foster Creek capital investment in 2013 is expected to be between $790 million and $870 million.

The next three expansions at Foster Creek, phases F, G and H, made significant progress in 2012, with overall work at Phase F now 65 per cent complete and start-up anticipated in the third quarter of 2014.

Progress is also being made on phases G and H. Cenovus anticipates submitting an application to regulators in 2013 for an additional Foster Creek expansion, Phase J. Ultimately, Cenovus expects Foster Creek will have the capacity to produce

14

per cent

Amount of oil production growth Cenovus expects in 2013

295,000 barrels per day and up to 310,000 barrels per day gross with optimization.

“We expect to continue delivering new phases at Foster Creek and Christina Lake at industry-leading capital efficiencies due to the talent of our workforce and our manufacturing approach to the development of these high-quality reservoirs,” Ferguson said. “We anticipate expansions at both projects will be brought on at a cost of $22,000–$25,000 per flowing barrel.”

Site preparation is already underway at Narrows Lake, with construction of the Phase A plant scheduled to start in the third quarter of 2013.

The first phase of the project is anticipated to have production capacity of 45,000 barrels per day, with first oil expected in 2017.

Capital investment in the project is forecast to be between $140 million and $160 million next year.

Capital efficiencies at Narrows Lake are anticipated to be between $28,000 and $32,000 per flowing barrel—well below the industry average.

— DAILY OIL BULLETIN

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J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

Suncor achieves first oil at Firebag 4 Suncor Energy Inc. achieved first oil throughout at its Firebag 4 facility, the producer said late last year.

Firebag 4 was safely commissioned during the third quarter of 2012, approximately three months ahead of the original schedule. The Firebag complex exited the month of November producing approximately 130,000 barrels per day.

As a result of unplanned maintenance in early November at its oilsands base plant, November oilsands production was lower than anticipated, averaging approximately 312,000 barrels per day.

Maintenance issues have been successfully resolved and the oilsands plant exited the month producing in excess of 380,000 barrels per day. Despite the maintenance issues in November, it was expected that oilsands production for 2012 would be at the lower end of the guidance range of 325,000–340,000 barrels per day.

Production numbers include upgraded sweet and sour synthetic crude oil and diesel as well as non-upgraded bitumen sold directly to the market from all Suncor-operated facilities. Reported volumes do not include Suncor’s proportionate production share from the Syncrude Canada Ltd. joint venture.

Suncor expected total production for 2012 to be within the company’s annual guidance range of 540,000–580,000 barrels equivalent per day.

— DAILY OIL BULLETIN

MEG plans on spending $1.94 billion in 2013 Oilsands player MEG Energy Corp. has set a 2013 capital budget of $1.94 billion for 2013, including $90 million deferred from previously planned 2012 investments.

The 2013 capital budget focuses investment on projects expected to generate the highest returns and lead to near-term production and cash flow gains, Bill McCaffrey, president and chief executive officer, said in a news release. “Accelerating cash flows further

Northeastern Alberta

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improve the company’s financial strength to support our significant growth plans.”

The largest portion of the 2013 capital investment plan ($480 million) is directed to MEG’s RISER initiative, which focuses on increasing production and throughput capacity from the company’s existing facilities in the near term. As part of the initiative, MEG plans to deploy enhanced modified steam and gas push (eMSAGP) technology to additional well pads in 2013.

Combined with initial production from the start-up of Christina Lake Phase 2B, which remains on budget and scheduled to begin steaming in the second half of the year, MEG is targeting average 2013 production volumes of 32,000–35,000 barrels per day with an exit rate of 37,000–43,000 barrels per day.

“Our production target for 2013 is approximately 20 per cent above projected 2012 volumes, and we expect further increases that will double current rates in 2014,” said McCaffrey.

At the same time, efficiency improvements with RISER are expected to reduce non-energy operating costs to $9–$11 per barrel in 2013 from MEG’s 2012 target of $10–$12 per barrel.

In addition to planned spending on the RISER initiative, MEG is planning to invest approximately $700 million in growth capital at the company’s Christina Lake project.

Planned investments include $170 million to complete construction of Phase 2B. Another $100 million will be spent on drilling and completion of an inventory of standby wells to take advantage of additional freed-up steam with the implementation of eMSAGP and $220 million for engineering, long lead-time items and site preparation for Phase 3A. A final capital cost estimate for Phase 3A is expected by mid-2013.

As MEG has continued to advance engineering for Christina Lake Phase 3A, it has been identifying synergies with plans for Phase 3B processing facilities, said McCaffrey.

“With twin plants located side by side, there are significant opportunities to optimize our investment for shared access, utilities and infrastructure, as well as leveraging our growing experience with RISER. We see significant benefits for both phases.”

Christina Lake Phase 3A is currently planned for completion in 2016. With future development phases at Christina Lake and the initial phase of MEG’s Surmont project, the company is continuing to target installed production capacity of 260,000 barrels per day by the end of 2020.

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CENTRAL ALBERTA WELL ACTIVITY DEC/11

DEC/12

Wells licensed

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DEC/11

DEC/12

Wells spudded

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DEC/11

Rigs released

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DEC/12

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Source: Daily Oil Bulletin

C.A.B. Central Alberta

Encana, PetroChina, partner in Duvernay

By Richard Macedo

Encana Corporation has entered into a joint-venture arrangement with Phoenix Duvernay Gas, a wholly owned subsidiary of PetroChina International Investment Company Ltd., to explore and develop Encana’s extensive undeveloped Duvernay land holdings in west-central Alberta.

Under the terms of the agreement, Phoenix will gain a non-controlling 49.9 per cent interest in Encana’s approximately 445,000 acres in the Duvernay play for total consideration of $2.18 billion.

At closing, $1.18 billion was paid to Encana and $1 billion is payable over the next four years in the form of a carry of half of Encana’s share of development capital.

During this period, the joint-venture partners plan to invest a total of $4 billion in new drilling, completion and processing facilities.

“This joint venture will build a foundation for the successful development of the Duvernay play.”

— Zhiming Li, president and chief

Photo: Joey Podlubny

executive officer, Phoenix Duvernay Gas

Encana estimates that the Duvernay jointventure lands contain about nine billion barrels equivalent of petroleum initially in place.

Encana remains the operator of the joint venture with its 50.1 per cent working interest.

Dirk Lever, managing director, institutional equity research with AltaCorp Capital Inc., said there are several points of key interest in this deal.

“It cer tainly does show t hat t he Chinese are happy with the opportunity to

invest in Canada via joint venture, which falls on the back of the federal government’s announcement on foreign takeovers,” he said.

Lever said that this joint venture is a generally positive announcement for the industry.

“There’s a lot of attention that’s going toward the Duvernay; it’s really at its early stages, but it does look like it has some terrific potential, and this capital will certainly help it get there,” he said.

It’s not a small-player’s game, Lever noted, pointing to Celtic Exploration Ltd.’s sale to Exxon Mobil Corporation.

“Now Encana’s got a partner in its Duvernay; this is a big-boy game, and it looks like they’re stepping up to the plate,” he said.

Phoenix’s investment demonstrates the tremendous value that Encana has created in the Duvernay and allows the company to accelerate the pace at which the full production potential of its Duvernay lands can be achieved, said Randy Eresman, Encana’s president and chief executive officer.

“A transaction of this magnitude keeps us on track to create a more diversified commodity portfolio and maintain our balance-sheet strength. It is a strong endorsement of Encana’s position as a reliable long-term partner,” he said in a news release.

Encana has drilled nine wells into the Duvernay, has five producing wells and currently has two rigs actively drilling additional wells. With the formation of this joint venture, Encana expects to more than double its planned pace of development in the Duvernay play beginning early in 2013. “ T he Duver nay project w ill combine Phoenix’s integrated upstream and

The partnership controls 445,000 net acres in the Duvernay.

downstream capabilities and financial resources with Encana’s proven resource play hub expertise. This joint venture will build a foundation for the successful development of the Duvernay play and help to diversify our business portfolio.

Encana is our ideal long-term partner for the development of our future natural gas business,” added Zhiming Li, Phoenix’s president and chief executive officer.

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

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J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

Whitecap Resources Inc. grew average production 144 per cent in the third quarter of 2012 to 15,795 barrels equivalent per day (69 per cent oil and natural gas liquids) from 6,485 barrels per day (64 per cent oil and natural gas liquids) in the prior year through strategic oil-weighted acquisitions as well as organic growth on existing and acquired properties.

The company said it achieved its third-quarter production guidance of between 15,500 and 16,000 barrels of oil equivalent per day while spending approximately $5 million less capital than anticipated, despite wet field-operating conditions in July that delayed much of its program.

Output for the nine months ended Sept. 30, 2012, averaged 13,056 barrel equivalent per day compared to 4,933 barrels per day for the same period last year.

For the three and nine months ended Sept. 30, 2012, capital expenditures, excluding acquisitions, totalled $74.75 million and $178.16 million, respectively, with over 96 per cent spent on drilling, completions and facilities.

In west-central Alberta, Whitecap continued to develop the Cardium resource play in the third quarter by drilling 19 (13.7 net) horizontal multi-frac light oil wells. This includes seven (six net) wells drilled in the Garrington Field. The company said it will continue to manage two to three drilling rigs in the area to drill Cardium horizontal wells. Whitecap had eight (seven net) Cardium horizontal oil wells planned for the remainder of 2012.

In the Peace River Arch area, Whitecap drilled two (1.5 net) Doe Creek horizontal oil wells and competed six (4.3 net) wells, including two (one net) Montney Sexsmith wells that are the most prolific Montney Sexsmith wells the company has drilled to date.

In west-central Saskatchewan, Whitecap drilled 17 (16.2 net) horizontal Viking oil wells in the Dodsland area while lowering capital costs and significantly improving the initial 30-day production rates for this light oil resource play. Total drilling and completion costs per well have continued to decrease, currently $900,000 from $1.1 million.

— DAILY OIL BULLETIN

Photo: Joey Podlubny

quarter of 2012.

Central Alberta

RMP focus on the Montney A 2013 exploration and development expenditures program of $85 million will focus on continued development of 100 per cent owned Montney light oil resource plays with plans to drill 14 wells, says RMP Energy Inc. The company expects to fund the 2013 capital budget from cash flow. RMP, though, said it possesses the fi nancial flexibility for additional funding through the company’s bank credit facility, which was recently expanded to $110 million, for any capital program expansions in 2013.

A t Wa sk a h ig a n i n we s t- c e nt r a l Alberta, the company plans to drill eight wells with five wells planned at Ante Creek and one well at Grizzly, southeast of the company’s Waskahigan asset base.

Drilling and completions are projected to account for approximately $57 million, with remaining budgeted funds of approximately $28 million allocated

towards investments in wellsite equipment, field facilities, gathering lines and strategic undeveloped land expansion.

Based on the budgeted capital expenditures anticipated within the budget, forecast average daily production is 6,000–6,500 barrels of oil equivalent per day, approximately 60 per cent light crude oil and natural gas liquids, and 40 per cent natural gas. Forecast production range represents a 15–25 per cent increase over the company’s 2012 average daily production estimate.

Notwithstanding strong budgeted production growth within a cash flow–based capital program, RMP’s forecast assumes limited gas processing capacity of approximately three million cubic feet per day at Ante Creek.

The company currently is facility limited for processing of associated solution gas at Ante Creek. The associated Montney solution gas is conserved and processed at an area operator’s gas plant. Oil production from Ante Creek is currently being trucked into RMP’s Waskahigan oil battery.

RMP said it is evaluating numerous gas take-away alternatives in order to increase processing capacity for 2013.

Additionally, the forecasted production assumes limited ability to truck oil during spring breakup surface conditions at Ante Creek. The company is factoring into its 2013 forecast reduced oil trucking loads of 50 per cent during the months of April and May. Assuming the median of the forecasted average daily production range and based on the current forward 2013 pricing assumptions of US$88.50 per barrel for West Texas Intermediate oil, an AECO gas price of $3.05 per gigajoule, an oil differential of $11.30 per barrel and an above-par Canadian dollar exchange rate of $1.01 (US$/C$), the company’s funds from operations for 2013 are estimated at $83 million (80 cents per share), an increase of 66 per cent and 60 per cent, respectively, over projected 2012 funds from operations.

For 2013, the company has 1,000 barrels per day of crude oil hedged with a fixed weighted average price of $100.17 per barrel.

— DAILY OIL BULLETIN

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Central Alberta

Stolberg drilling helps boost Manitok output fivefold Manitok Energy Inc. production averaged 2,525 barrels equivalent per day in the three months ended Sept. 30, 2012, a 510 per cent increase from the third quarter of 2011 due mainly to drilling in the Stolberg area, which contributed approximately 1,550 net barrels per day, and an acquisition in the central Alberta foothills.

The acquisition contributed approximately 930 net barrels equivalent per day.

The quarterly production increase was offset by the disposition of 350 barrels per day of heavy oil production in the Swimming area and the shut-in of approximately 210 barrels per day of sour natural gas production in the Solomon and Coleman areas during the second quarter of 2012.

Of the total capital spent during the quarter, approximately $13 million was directed to drilling, completion and equipping costs in the Stolberg area, and $2.2 million was related to geophysical expenditures.

Manitok anticipated exiting 2012 at approximately 3,800 barrels per day (about 60 per cent oil and condensate). The company anticipated a 2012 average production

Manitok anticipated exiting 2012 at approximately 3,800 barrels per day (about 60 per cent oil and condensate). It expects cash flow for 2012 to total $21.5 million. rate of about 2,430 barrels per day (39 per cent oil and condensate), with an expected 2012 cash flow of about $21.5 million.

As a result of the $18-million equity financing in October, year-end net debt was anticipated to be about $10 million, which was lower than expected.

The scope of the drilling program was altered during the year to adjust for the success at Stolberg and the fact that Manitok would meet its 2012 flow-through expenditure commitment by the third quarter of 2012 without having to drill a previously planned exploration well in another area.

Manitok has increased its net working interest from 7.4 to nine net wells of the anticipated 12 Cardium wells planned in the 2012 drilling program.

The increase in its working interest in the 2012 drilling program was due to the shift to higher working-interest wells at Stolberg from lower working-interest drills at Brown Creek and by farming in to two different partners’ working interests on several wells at Stolberg in the latter half of 2012.

— DAILY OIL BULLETIN

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J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

Central Alberta

Spartan nearly triples quarterly output Spartan Oil Corp. drilled 20 (18.4 net) wells in its Keystone core area in Pembina, Alta., during the third quarter of 2012 with a 100 per cent success rate, and produced 2,505 barrels equivalent per day (80 per cent oil and liquids), an increase of 277 per cent from the third quarter of 2011.

In approximately 15 months, Keystone has transformed the company from a start-up with approximately 600 barrels per day to a high-growth company with current volumes in excess of 4,000 barrels equivalent per day based on field estimates—entirely through the drill bit.

Spartan expected to bring on an additional 14 (13.9 net) wells prior to Dec. 31, 2012, all of which were already drilled and behind pipe, and to drill five more wells (4.9 net) before the end of the year.

From June 2011 to September 2012, Spartan drilled a total of 53 (48.6 net) horizontal wells and participated in an additional six (1.8 net) horizontal wells targeting Cardium light oil at its Keystone property with a 100 per cent success rate.

62

million

The amount Spartan will spend in 2013 to maintain production

The company said it has worked hard to become the most efficient Cardium driller in Pembina: the average time from spud to rig release for its horizontal wells is seven days.

Costs have continued to improve to the point where Spartan is now experiencing average on-stream costs for its Cardium horizontal wells of approximately $2.3 million ($2 million to drill and complete).

Operating expenses during the third quarter of 2012 were $8.54 per barrel equivalent compared to $13.79 per barrel

for the three months ended Sept. 30, 2011.

Spartan said it is encouraged by the drilling results in Keystone and initial rates continue to meet or exceed its internal type curve.

The company now has a total of 39 horizontal wells at Keystone that have at least 30 days of production (IP30).

The average IP30 oil rate for these wells is 158 barrels per day. Included in this number are 23 wells the company drilled in the interior of the main pool that have achieved an average IP30 oil rate of 123 barrels per day.

The company expects it will need to spend about $62 million in 2013 to maintain production at the forecast 2012 exit level of 4,500 barrels equivalent per day.

At that production rate, management’s internal forecast for 2013 cash f low is $92 million, leaving significant free cash flow to fund future growth, it said.

As of Sept. 30, 2012, the company had positive working capital of $20.9 million and no debt.

— DAILY OIL BULLETIN

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

37

SOUTHERN ALBERTA WELL ACTIVITY DEC/11

DEC/12

Wells licensed





DEC/11

DEC/12

Wells spudded





DEC/11

Rigs released



▼

▼

DEC/12



▼

Source: Daily Oil Bulletin

S.A.B. Southern Alberta

Federal cabinet rejects Cenovus Suffield shallow gas development

By Elsie Ross

Photo: Joey Podlubny

Citing the significant env i ron menta l impacts, the federal cabinet has refused to allow Cenovus Energy Inc. to develop a shallow natural gas infill project at Canadian Forces Base Suffield National Wildlife Area (CFB Suffield NWA) in southeastern Alberta.

In its first decision statement under t he ne w C a n ad i a n E nv i r on me nt a l Assessment Act, the government has decided that the significant adverse environmental effects by the project on one of the few remaining large blocks of dry mixed-grass prairie in Canada are not justified in the circumstances, Peter Kent, federal environment minister, said in a news release.

Cenovus proposed to drill up to 1,275 new shallow vertical gas wells within the boundary of the CFB Suffield NWA over a three-year period to recover an additional 125 billion cubic feet of gas.

T he projec t would essent ia l ly have doubled the existing 1,154 gas wells

installed before the area—50 kilometres northwest of Medicine Hat, Alta.—was declared a National Wildlife Area. The proposal would have included pipelines, access trails and other infrastructure. “ We m a ke t he se e nv i r on me nt a l assessment decisions based on the best available scientifi c evidence,” Kent said.

“This decision is a clear indication of our government’s commitment to strengthening environmental protection as a pillar of our responsible resource development initiative.”

The project has undergone a thorough environmental review based on the best available scientific evidence by an independent joint review panel under t he Ca nadia n E nv i ron menta l Assessment Act. In making its decision, the Government of Canada took into consideration the recommendations of the panel, as well as subsequent identification of critical habitat in the area for species at risk, and agreed with the panel’s

conclusions regarding the significance of the project’s environmental impacts.

“This decision also indicates that responsible resource development is not an automatic green light for all development projects, only those projects that meet our environmental rigour will be approved,” Kent added.

The minister also thanked the joint review panel chaired by Bob Connelly, with panel members Bill Ross and Gerry DeSorcy, for their hard work and dedication in conducting a thorough and open environmental review. The panel had released its report on Jan. 27, 2009.

The CFB Suffield NWA was created in recognition of its ecological integrity and the diversity and abundance of native plant and animal species. It is one of the few large blocks of dry mixed-grass prairie remaining in Canada and accounts for about 30 per cent of all the protected grasslands in Alberta. The NWA encompasses 458 square kilometres of

The federal government has stopped Cenovus from drilling almost 1,300 wells in southeastern Alberta at a time when shallow gas drilling is dead in the region.

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

39

Southern Alberta

40

DeeThree reports record production with Bakken, Belly River drilling

DeeThree drilled 16 wells in the Alberta Bakken in 2012.

Reporting third-quarter 2012 results in which it produced a record 4,692 barrels equivalent per day—a 120 per cent increase over the same quarter a year ago—DeeThree Exploration Ltd. plans on increasing capital spending in 2013.

DeeThree attributes its quarterly success to drilling Alberta Bakken and Belly River light oil resource plays.

By year-end, the company will have drilled 16 (16 net) Bakken wells, eight (7.5 net) Belly River wells, four (four net) Sunburst wells and one gross (0.3 net) nonoperated well in the Rycroft area.

During the third quarter of 2012, DeeThree drilled five (five net) wells on its Ferguson Alberta Bakken property with a 100 per cent success rate.

The quarter was highlighted by two wells testing 1,025 barrels per day and 743 barrels per day over a 10- and nine-day test, respectively, with these two wells to come on stream shortly.

The company reported that initial production and well declines continue to perform substantially better than the type curve used for internal budgeting purposes: an initial production rate of 300 barrels per day with a 65 per cent first-year decline rate.

J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

Judging from historical production and decline curves from its previously drilled wells, DeeThree said, its early production results indicate that longer horizontal legs exhibit the following characteristics: higher flow rates, higher initial production and flatter decline curves.

Also during the third quarter of 2012, DeeThree drilled nine (7.6 net) wells for an 89 per cent success rate, including two (1.8 net) horizontal Belly River wells, in the Brazeau area.

It drilled three (three net) Sunburst wells in the Lethbridge, Alta., area, two (0.8 net) non-operated Bakken wells and two horizontal Montney wells in the Rycroft area.

During the first nine months of 2012, DeeThree drilled 15 (15 net) wells at Lethbridge, six (5.6 net) wells at Brazeau and one (0.29 net) well at Rycroft for a 100 per cent success rate on 22 (20.9 net) wells year-to-date.

This compares to 13 (11.6 net) wells in the Brazeau, Lethbridge and Rycroft areas for a 92 per cent success rate a year ago.

Subsequent to quarter-end, the company tied in and brought on stream three (three net) wells.

Production over the fi rst two weeks of November averaged 5,750 barrels equivalent

Photo: Joey Podlubny

prairie grassland and hosts over 1,100 catalogued species, including 19 terrestrial species listed under the Species at Risk Act. The joint review panel was appointed on Nov. 16, 2006, by the minister of the environment and the chair of the former A lber ta E nerg y a nd Ut i l it ies Boa rd (predecessor to the Energy Resources Conser vation Board), to conduct an assessment of the project. In addition to written submissions, a public hearing provided an opportunity for the panel to receive and question information on the views of participants.

Public hearings were held in 2008 in Calgary and Medicine Hat. Participants who provided evidence at the hearing, in addition to the proponent, included t he Gover nment of Canada, t he Environmental Coalition, the Suffield Environmental Advisory Committee, the Suffield Industry Range Control, members of the public, environmental groups, energy companies and panel experts.

Under the Canadian Environmental Assessment Act 2012, the minster set a deadline of Dec. 3, 2012, for a government decision on the project.

Rhona DelFrari, a Cenovus spokeswoman, said that then EnCana Corporation applied for the approval in 2005—and obviously a lot has changed since then—and that the focus of Cenovus (after its split from EnCana) is now on developing its oil.

However, the company is still disappointed with the decision because it is confident it could have drilled the wells (425 per year in the winter) in a manner that would have minimal disturbance to the environment, she said. Cenovus has demonstrated that as it has been operating in the area for more than 40 years and is one of the parties that helped create the National Wildlife Area, said DelFrari. A National Wildlife Area is different from a national park in that multiple uses are allowed and it was always understood that oil and gas development could continue, she said.

With tens of thousands of gas wells, “this is a small number of wells” and will have little impact on the company, which uses gas as a natural hedge for its oilsands and refinery operations, said DelFrari.

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per day (71 per cent oil and natural gas liquids), based on field estimates with an additional seven (6.9 net) wells still to be brought on stream.

Drilling and completion costs have fallen throughout the year, with three of the past four one-mile lateral wells costing about $3 million.

DeeThree did not operate a drilling rig on its Belly River light oil property in the third quarter as it focused on drilling and delineating its Alberta Bakken play.

The company had one drilling rig operating in the area in December, drilling the second of a two-well fourth-quarter program. This fourth-quarter drilling program was testing the fourth distinct sand in this multi-zone play before year-end.

Now operating one drilling rig in each core area, it is drilling its 16th Alberta Bakken and eighth Belly River wells of 2012, substantially completing its planned capital drilling program.

Operating expenses for the third quarter of 2012 totalled $4.24 million or $9.83 per barrel, compared to $3 million or $15.26 per barrel in the same period last year and $3.79 million or $10.95 per barrel in the second quarter of 2012.

As volumes increase, the company has been able to realize economies of scale in the Lethbridge and Brazeau properties, contributing to a lower operating cost per barrel when compared to the second quarter of 2012.

For the third quarter of 2012, DeeThree spent $6.09 million (2011—$1.8 million) on tie-ins and facilities, which in 2012 consisted primarily of expenditures related to tie-in of the 2012 drills as well as construction of an amine plant and battery in the Lethbridge area.

As the company’s focus has shifted to drilling mainly in the Brazeau and Lethbridge properties this year; no capital was spent on acquisitions in 2012.

For the nine-month period, drilling and completion expenditures totalled $77.67 million (2011—$35.32 million), equipment and facility costs were $12.15 million (2011—$2.04 million), $8.6 million (2011—$2.64 million) was spent on land purchases, $169,000 was spent related to the purchase of seismic programs (2011—$33,000), and the remaining $1.04 million (2011— $588,000) was invested in capitalized general and administrative, and other corporate assets.

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SASKATCHEWAN WELL ACTIVITY DEC/11

DEC/12

Wells licensed





DEC/11

DEC/12

Wells spudded





DEC/11

Rigs released



▲

▼

Saskatchewan

DEC/12



▼

Source: Daily Oil Bulletin

Crescent Point plans $1.35-billion capital budget

Photo: Pipeline News

Crescent Point Energy Corp. has set a $1.35-billion capital-development budget for 2013.

Execution of the budget is expected to increase average daily production to 112,000 barrels of oil equivalent per day, with a 2013 exit rate of 114,000 barrels per day. The 2013 capital program is consistent with the company’s fi ve-year growth models, which forecast long-term production per share growth and dividend sustainability under a variety of commodity price scenarios.

“In 2012, we advanced new technologies across our major plays and expect to deliver production per share growth greater than 10 per cent. We will focus on organic growth and the integration of assets from key acquisitions, and continue to build upon our success over the last couple of years,” Scott Saxberg, president and chief executive officer, said in a news release. “The 2013 budget is focused on the development of our major oil resource

plays in the Bakken, Shaunavon and Uinta Basin and on enhancing our portfolio of emerging resource plays.”

As in previous years, Crescent Point’s 2013 guidance includes the assumption of a long spring breakup and the anticipated production impact of converting producing wells to water injection wells in the Bakken and Shaunavon resource plays.

In total, approximately $1.17 billion, or 87 per cent of the budget, is expected to be allocated to drilling and completions, with a total of 455 net wells planned. The remaining $180 million of the budget is expected to be allocated to investments in infrastructure, undeveloped land and seismic across all core areas.

Crescent Point expects to spend approximately $510 million of its 2013 budget in the Viewfield Bakken and Flat Lake areas of southeastern Saskatchewan, including drilling approximately 163 net wells in the Viewfield area and 15 net wells at Flat Lake. The company plans to continue

Crescent Point plans on spending over $500 million in the Bakken, drilling 152 net wells.

to invest in infrastructure projects to accommodate continued growth of the company’s Bakken production, including preliminary expenditures related to the expansion of the Viewfield gas plant to 42 million cubic feet per day from 30 million cubic feet per day.

In the Shaunavon area of southwestern Saskatchewan, Crescent Point plans to spend approximately $283 million of the 2013 budget, including drilling approximately 89 net wells, which will target both the Lower Shaunavon and the Upper Shaunavon resource plays. The company

114,000 Barrels per day Crescent Point forecasts for 2013 exit production

plans to continue to invest in infrastructure projects to accommodate production growth in this play, including the expansion of the Dollard rail facility to more than 10,000 barrels per day from 4,000 barrels per day.

In Alberta, the company plans to spend approximately $158 million, including drilling up to 45 net wells. The majority of the planned expenditures and drilling for Alberta is expected to be allocated to the emerging Swan Hills Beaverhill Lake light oil resource play and the Provost area. The company will also continue to pursue its exploration and development projects in southern Alberta in 2013.

In the United States, Crescent Point plans to spend approximately $242 million. In the Uinta Basin light oil resource play in northeastern Utah, the company plans to spend approximately $195 million of the 2013 budget, including drilling approximately 74 net wells and investing $10 million in facilities and infrastructure.

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

43

Saskatchewan

Crescent Point has allocated the remaining $157 million of the capital development budget to other properties in Saskatchewan and Manitoba, including conventional assets in southeastern Saskatchewan and Battrum/Cantuar.

“Based on continued positive waterflood response in our core Bakken and Shaunavon resource plays, we have increased our waterflood capital for 2013 relative to 2012,” Saxberg added. “In addition, we’ll expand the waterf lood program to include our Beaverhill Lake,

Uinta Basin, Alberta Viking and Manitoba Bakken plays.”

The company also is preparing an incremental budget for the second half of 2013, the implementation of which will depend on commodity prices. The incremental budget will be focused on the company’s Beaverhill Lake and North Dakota resource plays, as well as its emerging resource plays in Alberta.

In 2013, the company plans to drill 455 net wells of its more than 7,700 net internally identified low-risk drilling locations

in inventory. This drilling-inventory depth positions the company well for long-term sustainable growth in production, reserves and net asset value, and provides long-term support for dividends.

“The 2013 capital budget provides for organic growth across our core resource plays, while maintaining a strong balance sheet and dividend sustainability,” Saxberg said. “We continue to manage volatile WTI [West Texas Intermediate] prices and differentials through our various hedging programs.”

— DAILY OIL BULLETIN

Longview plans to drill 17 wells into the Midale play in 2013.

A $36-million capital program for 2013 will focus on Midale light oil development in southeastern Saskatchewan with plans for 17 (13.1 net) wells out of a total of 28 (21.9 net) wells in Alberta and Saskatchewan, said Longview Oil Corp.

Another two horizontal Shaunavon/ Frobisher formation wells will be drilled in southeastern Saskatchewan. Capital expenditures will be comprised of lowrisk crude oil drilling and recompletion activities in areas with high netbacks where L ong v iew op er ate s e x i st i ng infrastructure. Drilling operations will focus on areas where recent activity has demonstrated strong economics that result 44

in a quick and positive impact on funds from operations while limiting facility and other infrastructure expenditures to a minimum, the junior added.

The budget will preserve a strong balance sheet while using cash flow to maintain its current dividend policy and fund substantially all capital expenditures while maintaining production at 2012 levels, said the company. A base decline rate of approxi mately 19 per cent allows it to maintain production with a modest level of capital expenditures, said Longview.

Longview’s 2013 capital drilling program is primarily focused on further de velopment of its Midale and Frobisher

J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

plays in southeastern Saskatchewan where it has an extensive undeveloped land base of 106 (87 net) sections, high working interests, fee-title ownership and existing infrastructure. Although drilling activities in the area were limited in 2011 due to extremely wet weather conditions, results through 2012 have demonstrated strong results with potential for scalability in six different project areas, said the company.

Recent horizontal drilling programs in the Mississippian Midale and Frobisher formations have yielded 30-day initial oil production rates ranging between 60 and 160 barrels per day with all in well costs of $1.1 million to $1.4 million.

Approximately 60 per cent of the capital budget is allocated to southeastern Saskatchewan targeting six different project areas where Longview has existing infrastructure, which will result in lower operating costs for new production. These are lower-risk locations primarily targeting the Midale formation that are offset by nearby production where successful results will lead to additional drilling in future years.

Longview said its existing waterflood projects have demonstrated positive results due to capital expenditures incurred in the last several years, which were undertaken to enhance water injection rates and flood patterns.

It will allocate funds in 2013 to further enhance existing waterflood projects at Nevis, Sunset and Pembina in Alberta and Eyehill in Saskatchewan. These enhancements will set up future drilling opportunities as voidage replacement and reservoir pressures reach certain levels in each property.

— DAILY OIL BULLETIN

Photo: Joey Podlubny

Longview targets Midale in 2013

Saskatchewan

Raging River pinpoints Viking for 2013 growth A $120-million capital-development budget for 2013 will focus entirely on the Viking light oil resource play in Raging River Exploration Inc.’s southwestern Saskatchewan core area, said the company.

The budget provides for the drilling of 115 net horizontal Viking oil wells. Total on-stream costs (drilling, completion and equipping) are expected to be $108 million or 90 per cent of the approved budget. The remaining $12 million is allocated to land, seismic and maintenance capital throughout the Dodsland area.

Raging River plans to finance the budget through funds from operations, anticipated to be in excess of $80 million, and the use of its existing credit facility.

The 115 net wells to be drilled, including an anticipated 30 net wells during the first quarter of 2013, represent approximately 10 per cent of the company’s currently defi ned low-risk drilling inventory.

Based on the current pace of development, Raging River says it has a 10-year drilling inventory positioning it for long-term, sustainable, per-share production, reserves and value growth.

Execution of the planned expenditures is expected to more than double 2013 average daily production to 4,600 barrels of oil equivalent per day (95 per cent oil) from its average of 2,200 barrels per day in 2012.

The 2013 forecast exit rate is approximately 5,400 barrels per day, up more than 45 per cent from 2012’s forecast exit rate of 3,700 barrels per day, which was achieved in early December.

The company said it anticipates that the price differentials between West Texas Intermediate and Edmonton Light Oil will remain volatile through 2013 and therefore has assumed an average price of $80 per barrel for Edmonton Light. It continues to actively manage differentials through increasing crude deliveries on rail and anticipates having up to 30 per cent of corporate oil volumes on rail in January.

Its 2012 capital program has been completed, and the company anticipated being back actively drilling in early January 2013.

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— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

45

Saskatchewan

Final land sale of 2012 draws $11.53 million, including $1 million for oilsands rights The December sale of Crown petroleum and natural gas and oilsands rights in Saskatchewan generated $11.53 million in revenue for the province, bringing the final 2012 tally to $105.69 million.

This sale featured five oilsands special exploratory permits north of the Primrose Lake Air Weapons Range being offered, two of which received acceptable bids.

The two oilsands parcels received bids of just over $1 million for 196,995 hectares, which works out to an average price of $5.09 per hectare.

In the first week of 2013, a total of 214,593 hectares exchanged hands at an average of $53.72. For 2012, the province sold 397,119 hectares at an average of $266.13 per hectare. Last year, Saskatchewan attracted $248.77 million in bonus bids on 504,395 hectares at an average of $493.21.

“It is encouraging that more than $1 m i l l ion in bonus bids was received

for two of the oilsands permits that were offered in this sale,” said Energy Minister Tim McMillan. “In addition to a bonus bid, these permits require a minimum workcommitment expenditure to be spent in exploration over the five-year term of the permits. The province is cautiously optimistic that the results of this exploratory work will provide further insight into the potential of the resource in the province.”

“I have not looked at the specific parcels involved but, in general…Saskatchewan oilsands are relatively remote from infrastructure compared to most Alberta projects, so that will add greatly to capital expenditures required,” said Brad Hayes, president of Petrel Robertson Consulting Ltd. “With there being far fewer thermal projects and no oilsands mining in Saskatchewan, investors might discount value with the thought that the regulatory regime may be less flexible than in Alberta.”

He added that, geologically, the big regional traps for oilsands reach an eastern edge west of the Alberta-Saskatchewan border. There can still be oilsands deposits in Saskatchewan, but until they are fully appraised, investors will see a relatively large risk that resource volumes and reservoir continuity may not be sufficient to support an economic project.

Saskatchewan’s December sale included 89 lease parcels that brought in $8.89 million in bonus bids, two petroleum and natural gas exploration licences that sold for $1.63 million and two oilsands special exploratory permits that received $1 million.

The Weyburn-Estevan area received the most bids with sales of $6.1 million. The Lloydminster area was next at $2.6 million, followed by the Swift Current area at $1.8 million and the Kindersley-Kerrobert area at $982,890.

— DAILY OIL BULLETIN

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News Tech

The latest regional technology news

Cenovus submitting new rig technology to COSIA

Photo: Joey Podlubny

By Lynda Harrison

Traditional oilsands drilling at Cold Lake. The new rig would be brought in by helicopter.

Cenovus Energy Inc. has developed a drilling rig that can be flown by helicopter to remote areas, cutting out the need to build access roads and saving about 25 per cent, or around $100 million per year, in costs.

The company has been working on the technology for two years and plans to submit its research to the Canadian Oil Sands Innovation Alliance as its contribution to furthering the reduction of the oilsands industry’s environmental footprint, said Harbir Chhina, executive vice-president of oilsands.

“We don’t need to have ice bridges, things like that,” said Chhina. “At Borealis, we really couldn’t do a stratigraphic well drilling program unless we had 40–50 wells because you have to trigger camps and road access. With this rig, we can drill one, two, three, 50 wells—whatever we want.”

The SkyStrat drilling rig spudded about 16 wells in 2012, and a second rig is to be built in 2013, Chhina said in a conference call about the company’s 2013 budget.

In 2013, about 25 stratigraphic, or strat, wells will be drilled with the new technology in the Steepbank and East McMurray area of the Borealis project.

Cenovus borrowed the idea from the hard-rock mining industry by putting a blowout preventer and a well control system on a mining rig, said Jessica Wilkinson, company spokeswoman.

Because it only has the prototype to go on, the company won’t have a firm number on how much it costs to build the rigs until the second one is complete, said Wilkinson.

In 2013, about 25 stratigraphic wells will be drilled with the new technology in the Steepbank and East McMurray area of the Borealis project.

The technology has proven to reduce the amount of water needed to drill a well by up to 50 per cent and does away with the need to use water to freeze in temporary infrastructure such as roads, she said.

A typical strat well uses about 100 cubic metres of water but the new rigs have cut that to about 50 cubic metres, she said.

The company drills 300 –500 strat wells per year, the majority in the oilsands.

The new rig is also expected to require a smaller well pad, but the amount of reduction won’t be determined until next year as, up to now, the company has only been using it on existing well pads, she added.

The crew can be transported by helicopter as well.

The new rig also allows year-round drilling, labour efficiencies and promotes safety “because you’re working with the same crews throughout the whole year,” said Chhina.

Cenovus plans to drill 363 strat wells this year, down from an estimated 478 such wells in 2012 and 480 in 2011.

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

47

Te c h N e w s

Portable oilsands plants could solve many challenges, forum hears

By Lynda Harrison

48

By Lynda Harrison

Off-site construction of the portable plants will reduce worker costs.

Environmental challenges are also addressed through minimization of land disturbance, human intrusion, water requirements and air emissions.

The plants use only 10–20 per cent of the typical plot space, off-site construction eliminates the need for large work camps, there is no need for large storm and blowdown ponds, and power generation is internal so there are no power transmission lines, she said.

The highly automated design reduces staffing, and assembly is done quickly with a small team, said Reilly.

Water recycle rates are greater than 95 per cent, water disposal rates are 0.1– 0.2 barrels of water per barrel of oil and they enable the use of waste water as feed stream. To cut down on air emissions, the designs use a high degree of heat integration and natural gas as fuel, she said.

J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

Maximizing oilsands’ market value and product marketability—in other words, improving product quality—is equally as important as market diversification to the future of the oilsands industry, which is facing unprecedented risks, and certain technologies merit further attention, said a noted Alberta scientist.

“I think everybody knows our exports need to be diversified, primarily because of declining demand, increasing U.S. domestic supply, and because of the large differential…we are leaving a lot of dollars on the table so oilsands growth will be dependent on other transportation options, but there are technologies that we need to also focus on to maximize current oilsands’ market value,” said Eddy Isaacs, chief executive officer of Alberta Innovates – Energy & Environment Solutions (AI-EES). “I think that’s a priority for Alberta producers.”

Canadian crude contains a large amount of vacuum residue—especially in its diluted bitumen—and its total acid number, sulphur and aromatics contents are high, so there is a discount from refineries that can process it, Isaacs told an oilsands conference in Calgary.

To improve the quality of crude before it goes to refineries, AI-EES, Statoil Canada Ltd. and UOP LLC have been working on a slurry-phase bitumen upgrading project based on Canada Centre for Minerals and Energy Technology hydrocracking technology that has led to a technology that’s being licensed by UOP, said Isaacs.

AI-EES has also been working with MEG Energy Corp. on a partial upgrading process called HI-Q, which uses two key process elements: a thermal cracker and a solvent de-asphalter that works through precipitation. It removes large molecules containing impurities such as metals and difficult-toprocess sulphur compounds.

He said environmental concerns such as greenhouse gas emissions, air quality, land disturbance, tailings and water use are starting to be addressed through Canada’s Oil Sands Innovation Alliance, a recently announced

Photo: Joey Podlubny

A manufacturer of standardized, portable steam assisted gravity drainage (SAGD) facilities said they are designed to address many of the challenges associated with this type of in situ development.

Calgary-based Oak Point Energy Ltd. has three designs—small, medium and large—for modular, portable SAGD plants that can be assembled in 30 days. In addition, the plants can be manufactured in lower-cost environments such as Ontario, Nina Reilly, vice-president of technology and supply chain at Oak Point, told a CI Energy Group conference in Calgary.

“Standard configurations allow you to drive economy of scale in your manufacturing, apply continuous improvement in your design and drive standardization in the components, or the vessels that go into those designs,” said Reilly.

Its smallest design, called UltraLite, is essentially a pilot-scale plant, she said. With capacity of 1,260 barrels per day, it creates enough steam to serve one or two wells.

Its OneSite design is for small commercial production of up to 7,200 barrels per day with eight to 12 well pairs.

“You could use it where you have a small resource or discontiguous resources.

You’ve got little pods that you want to exploit. Collectively, there’s a lot of bitumen, but each little pod in and of itself is difficult to justify economically.”

The largest plant design, the MultiSite, has a capacity of 21,000 barrels per day with two to four well pads.

Grizzly Oil Sands ULC is about to commission a OneSite plant based on Oak Point’s design, Reilly said.

Grizzly has an 11,300-barrel-per-day project, Algar Lake, which will be built in two phases with each producing 5,560 barrels per day of bitumen. The first phase is scheduled for an early 2013 start-up.

Reilly told the forum Oak Point’s designs have been engineered to address known challenges to operating oilsands plants, including reducing capital costs.

There are many costs savings in engineering and procurement, and a lot of equipment is eliminated, she said.

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environmental monitoring agency; Alberta Energy Resources Conservation Board tailing management regulations such as Directive 74; and Alberta’s Land-Use Framework.

“However we are still very vulnerable on GHG [greenhouse gas] emissions, and I think that’s one of the areas we have to pay a lot of attention to,” said Isaacs.

Solvent and steam-solvent processes such as those being pioneered by Cenovus Energy Inc. and Imperial Oil Limited will have to be looked at in a very deliberate way to make the most of these processes and get the best recovery, he said.

But resource depth, reservoir quality and, most importantly, the cost, mobility and loss of solvents in the reservoir are serious challenges that will have to be overcome “even though today they can be taken off the shelf and used commercially.”

In situ combustion also needs closer scrutiny, he added. A number of processes have been developed—combustion override split-production horizontal-well, top-down combustion, toe to heel air injection (THAI), catalytic THAI—however, they, too, have unsolved issues, he said.

“We still are not clear about how the maximum temperature reduces with time, how long can high-temperature zones be maintained; sweep efficiency is another question mark and the potential for high CO2 emissions.”

According to Isaacs, electrical processes have their own challenges: where will the electricity come from, the efficiency of transfer, land disturbance and process efficiency.

One up-and-coming technology, the enhanced solvent extraction incorporating electromagnetic heating, is looking promising, he said.

“These are the types of technologies that I think are going to be very critical if we’re going to be successful in reducing GHG emissions, water and energy use.”

Isaacs suggested that perhaps industry has not been innovative enough and that several technologies that have been “bouncing around” merit further investigation, such as Suncor Energy Inc.’s reflux solvent process.

There is also the FAST-SAGD process, developed by the Alberta Research Council (now Alberta Innovates – Technology Futures) and the University of Alberta, he noted. The process had an offset well set some distance from the steam chamber, which came into production about three years after steaming.

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Cover Feature

T

he tight oil boom brought about by the application of extended reach horizontal drilling and multistage fracturing is still in its early stages, with years of exploration drilling and decades of development drilling still to come.

But unconventional oil producers are already laying the groundwork for future production growth as they pilot and commercialize enhanced oil recovery (EOR) schemes in basins across western Canada.

Crescent Point Energy Corp., a pioneer in the tight oil drilling and completion revolution, is also pioneering EOR using waterfloods at its Bakken and Shaunavon plays in southern Saskatchewan.

The company believes it can add as much as a billion barrels of reserves through waterfloods as it develops its assets.

At the end of the third quarter, Crescent Point had 48 injector wells in its waterflood operations in the Bakken and 11 in the Shaunavon.

Company president and chief executive officer Scott Saxberg told analysts during Crescent Point’s

have four years of flat production, and in newer pilots we are seeing very similar results.”

Saxberg also told analysts the waterfloods are also slowly adding to the reserves base in both the Bakken and Shaunavon. Growth in reserves is being tempered somewhat as producing wells are converted to injectors and reserves are lost on those wells.

“So we lose reserves on those injectors, and then they get added to the offset producers, so you kind of wind up with the net zero in the short term, but we’re seeing pretty strong performance across the board not only at the Bakken but also the Shaunavon,” he said. “As we get more data as time goes by, we’ll add reserves on those wells, and it just sort of gets built into our long-term reserve additions with minimal capital. It’s long-term year-over-year additions. We don’t expect to go from like a 12 per cent recovery to 20 per cent or something overnight.

That’s just the nature of how conservative engineers book reserves at year-end. We know technically

“In our original pilot that came on in the Shaunavon three years ago, we now have four years of flat production, and in newer pilots we are seeing very similar results.”

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

third-quarter conference call that the early results of the waterfloods have been encouraging in stemming the steep declines common for tight oil plays.

“When you look at the overall field, in wells that aren’t in and around the waterfront, we’re seeing like 38 per cent field declines,” he explained. “Then, when you do a review of all the wells affected by the waterflood injectors, about 94 wells, you are only seeing about a five per cent drop in that decline rate at this moment. So just on a high-level basis, it’s been about a five to six per cent change to the decline based on just doing a comparative of the waterflood at this stage. It’s obviously early stages in the waterflood in that majority of those 41 wells we just put on this year into the flood. When you look at it historically, in our original patterns in the field, we’ve seen flat production for one to three years in some of the original offset wells that we started back four years ago. So, as we add more injectors and unitize the heart of the field, we’re going to see flatter and flatter production in those areas and on a larger base production.

“We’re seeing the exact same or similar results in Shaunavon,” he added. “In our original pilot that came on in the Shaunavon three years ago, we now

recovery factors are going to be in the mid–30 per cent range.”

Saxberg said he’s become more and more convinced of the ability of waterfloods to add to reserves in tight oil plays as the company has advanced its knowledge of how the reservoirs operate.

“I’m more convinced as we’ve drilled more wells.

We’ve drilled well over 2,000 multistage horizontal wells in Canada, and through these wells, and then with more waterflood data, we’re seeing that unconventional type reservoirs act more like a conventional reservoir. And so you may see recovery factors move more towards the conventional recovery factor versus the initial theory of low recovery in these types of reservoirs.”

Petrobakken Energy Ltd., another pioneer in tight oil development in Saskatchewan, is also building towards commercializing EOR in the tight oil formations of southeastern Saskatchewan. And, like Crescent Point, it has the potential to add hundreds of millions of barrels of future production if successful.

Rene LaPrade, senior vice-president for operations at Petrobakken, told analysts early this fall they are well on their way to proving

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the effectiveness of using natural gas to force oil out of the tight Bakken formation.

“We have two pilots that are running presently, and these aren’t experiments,” said LaPrade. “They’re actual full pilots that we’ve had injection into. One is a parallel gas injection, an infill well that we have on gas injection. That started in June of [2012]. We’re starting to see some encouraging results with that pilot. And we have the existing toe [to heel air] injection gas pilot where we’re putting about one million cubic feet a day of gas into it, and we’re also seeing some very encouraging results.”

Outside the Bakken and Shaunavon, a number of producers are testing enhanced recovery technologies in tight oilfields across western Canada.

In the Beaverhill Lake play north of Edmonton, Arcan Resources Ltd. spent much of 2012 building out infrastructure and drilling injector wells. Arcan is looking to get its tight oil wells on enhanced production in the early stages of development to stem declines and add to long-term reserves.

“Based on waterflood recoveries of up to 40 per cent in offsetting areas of the Swan Hills Beaverhill lake reservoir, Arcan is of the view that similar waterflood recovery rates on its property would have the potential to translate into recoveries of up to 270 million barrels [95 per cent light oil] from the Arcan waterflood area,” the company said in its third-quarter update.

Penn West Exploration is also developing a waterflood program for its carbonate development at Swan Hills. It also sees potential in the Cardium play covering a huge swath of westcentral Alberta.

“We see this as a very significant piece of our business going forward, the marriage of horizontal technology and EOR technology,” Murray Nunns, president and chief executive officer, told analysts during a conference call last year.

While Penn West believes the carbonate and Cardium plays are going to be key centres for enhanced recovery, it has about 150 other waterflood and EOR projects across western Canada, he said. “We are going to be looking at virtually all of them because we believe it represents a massive long-term opportunity for us.”

At Otter, the major focus of current development in the Slave Point carbonate play, the company has already submitted an application for a waterflood, said Bob Shepherd, senior vicepresident of EOR. “Most of that play looks amenable to waterflood,” he said.

Penn West would like to have water going in the ground in the fi rst quarter of 2013 as the beginning of a continuous buildout of a waterflood program in the area, he added. To optimize ultimate recovery, it wants to keep the EOR program within one to two years of the development program.

The Viking tight oil play is another target for secondary recovery. Raging River Exploration Inc. has been running a pilot in the play since 2011. In a recent presentation, Raging River said proven vertical waterfloods in the Viking have increased recovery by over one million barrels per square mile. Its pilot is testing horizontal waterflood techniques.

Raging River believes it could increase recovery factors from eight per cent from primary recovery methods to 16–20 per cent with the addition of waterfloods. Some existing Viking waterfloods have increased recovery factors to as high as 30 per cent.

Feature

Taking shape Pieces of CO2 enhanced oil recovery industry puzzle coming together in Alberta

By Pat Roche and Jim Bentein

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E

arly in the new century, CO2 enhanced oil recovery (EOR) looked like it had a bright future in western Canada.

The Weyburn CO2 miscible flood project in southeastern Saskatchewan was in commercial operation. Studies launched in Alberta showed the potential to capture an additional billion barrels of oil using the technology.

Then things stalled out as the natural gas boom turned industry away from oil production. This was followed by the global financial debacle in 2008 and then the shale gas and tight oil revolutions leading to today.

Yet despite being out of the headlines, efforts have continued in developing the infrastructure needed for large-scale CO2 flooding operations. And those efforts are now moving forward. Work towards the pipeline meant to kick-start CO2-based EOR in Alberta is continuing while the planned upgrader/refinery that will be the pipeline’s main CO2 source advances.

Enhance Energy Inc., which was chosen by the Alberta government to build the pipeline and related CO2 capture facilities, is continuing preliminary work. Besides spurring EOR in central Alberta’s mature oilfields, the Alberta Carbon Trunk Line will divert CO2 from the atmosphere as part of the province’s greenhouse gas emissions reduction strategy.

Privately held Enhance plans to build a 240-kilometre, 16-inch-diameter pipeline capable of shipping 40,000 tonnes of CO2 per day. The initial volume of about 5,000 tonnes of CO2 per day will come from the proposed upgrader/refinery and an Agrium Inc. fertilizer plant, both northeast of Edmonton. The proposed pipeline will initially ship CO2 to a mature light-oil property at Clive in central Alberta, which Enhance owns jointly with Fairborne Energy Ltd. Enhance and the Alberta government hope more oil producers will sign up to take CO2 once the pipeline is built, resulting in other EOR projects being announced.

About 800–1,600 tonnes per day of CO2 is to come from Agrium. Enhance is depending on the planned upgrader/ refinery to supply the rest of the pipeline’s initial 5,000 tonnes per day.

Speaking at a Petroleum Technology Alliance Canada CO2 conference in October 2012, Enhance president Susan Cole said detailed engineering for the Agrium carbon capture facility has been done. All of the major mechanical equipment has been procured and the on-site tie-in to the Agrium plant completed.

“We have purchased all the major mechanical equipment for the site; it has already started showing up. So we’ve made quite a bit of progress on the Agrium capture facility,” she said.

“We decided to build that adjacent to the site. We were originally going to build it inside the Agrium facility, but it just made more sense to move it just to the edge. That project should be starting construction next year [2013].”

The Agrium capture facility will include dehydration equipment because the CO2 is wet. Otherwise the Agrium stream is a highly pure form of CO2 needed for EOR. (Most industrial facilities—such as coal-fired power plants—emit a highly diluted CO2 stream, which is too costly to purify.)

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Enhance is currently doing detailed engineering for the CO2 capture facility at the upgrader/refinery and “we should be moving into procurement next year,” Cole said.

As for the pipeline itself, surveying and the construction plans should be complete by the end of this year, and specifications for the pipe have been finalized.

“And the next step…is to just purchase the pipe, and that doesn’t take a very long time,” she added. “So we would be looking at construction for the pipeline probably in 2014.”

The models for the Enhance project are the CO2-based EOR project that has operated at Weyburn in southern Saskatchewan for more than a decade and the Alberta Gas Trunk Line.

The Alberta Gas Trunk Line was a natural gas pipeline system initiated by the Alberta government in the 1950s. In the early decades of Alberta’s oilpatch, natural gas was seen mostly as a hindrance to oil production, and about a trillion cubic feet of gas was flared before the province’s Energy Resources Conservation Board was created to conserve the resource.

In a move that helped spur the development of Alberta’s natural gas industry, the government facilitated the creation of the Alberta Gas Trunk Line to get the gas to market. That initial trunk line grew into today’s massive province-wide natural gas pipeline system that is owned and operated by the private sector.

The thinking behind Enhance’s Alberta Carbon Trunk Line is similar. Today, roughly 70 per cent of Alberta’s light oil reserves are left in the ground after primary and secondary production end. Studies have indicated that more than a billion barrels of additional light oil could be recovered from Alberta’s mature fields by injecting CO2.

However, despite a flurry of government-funded pilots last decade, CO2-based EOR has stalled in Alberta. Lack of an affordable supply of CO2 has been blamed for the failure of large-scale EOR projects to materialize in Alberta.

Another factor that has been cited is the greatly improved ability to drill long horizontal wells with multiple fracture stimulations per wellbore. This technology, which some producers have called EOR, has reversed the long decline in Alberta’s light oil production. For most producers, drilling wells is more attractive than capital-intensive CO2based EOR projects, which have long payback periods.

Canada’s biggest CO2-based EOR effort—Saskatchewan’s Weyburn project—is currently producing about 27,000 barrels per day of light oil (about 16,000 barrels per day net to the operator, Cenovus Energy Inc.), according to Cenovus.

When the Weyburn project was being planned and developed in the 1990s, West Texas Intermediate crude was barely US$20 per barrel compared to the current price of roughly US$90.

Over its life, the project is expected to recover 155 million barrels of oil beyond what has been produced on primary production and waterflooding, according to Enhance.

The Weyburn project will also dispose of 45 million tonnes of CO2, which means it is also currently the world’s largest carbon capture and storage project.

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Cole, who managed development of the Weyburn project when she worked at PanCanadian Petroleum Ltd. (a predecessor of Cenovus), sees Weyburn as a template for Alberta.

“What we’re doing today with the Alberta Carbon Trunk Line is pretty much the same thing,” she said.

To spur CO2-based tertiary recovery in Alberta, the government committed $495 million—spread over several years—to Enhance for the proposed pipeline and CO2 capture facilities. Cole said the pipeline itself is expected to cost about $250 million, but the price tag for the whole project—including operating costs and the CO2 capture facilities—is about $1.5 billion.

With the pipeline work underway, the next step in building the CO2-based infrastructure fell into place in November when North West Upgrading Inc. and partner Canadian Natural Resources Limited sanctioned the Sturgeon Refinery project that will supply most of the CO2.

The go-ahead for a long-planned oilsands bitumen upgrader will ultimately lead to $100 billion or more in investments in Alberta, according to the chairman of the companies developing the projects.

“I can’t even estimate the total economic impact, but it will be in excess of $50 billion and closer to $100 billion and beyond,” said Ian MacGregor, North West Upgrading’s chairman, who was commenting on the announcement that the board of the North West Redwater Partnership (NWR) had agreed to proceed with the first phase of the project, which will cost $5.7 billion.

NWR is a wholly owned subsidiary of Calgary-based North West Upgrading and Canadian Natural Upgrading Limited, which, in turn, is a subsidiary of Canadian Natural Resources.

“We will be capturing enormous quantities of CO2,” he said.

“Initially, we will be capturing 3,500 tonnes of CO2 a day, but with all three phases we would be capturing up to 11,000 tonnes. That’s equal to the emissions from all the cars in Alberta. This is an important

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project for Alberta. It’s being done by Albertans. We live here, and we wanted to do the right thing.”

But he said the project makes economic sense, too, because of its value-added component.

“This is the first refinery in the world that incorporates CO2 capture into the initial design,” he said.

He said it also needs to be understood that the company really isn’t building just an upgrader, deploying conventional coking technology to convert Alberta bitumen into lighter crude ready to be refined into gasoline, lubricants and other petroleum-based producers.

“Most refineries in North America were designed to produce gasoline, but we are responding to the market in western Canada,” said MacGregor. “We’re producing 40,000 barrels a day of diesel [from the first phase], and diesel is a high-margin product that is in great demand in western Canada.”

He said NWR’s studies have shown there is a market in western Canada for the entire amount of diesel the project would produce from the first one and a half phases.

The project would employ technologies commonly used in upgrading and refining. However, in a key departure, it will also use gasification technology.

The advantage of using gasification is that the upgrader won’t need to rely on natural gas as a source of hydrogen for the process.

Instead of producing dry coke as a by-product, North West will transform hot liquid bottom ends into hydrogen, oxygen and pure CO2.

“It produces 99.5 per cent pure CO2,” said MacGregor.

Most CO2 from conventional upgraders is mixed with nitrogen and other elements, which make it unsuitable for EOR. But in the case of North West, the CO2 it will produce will be a valuable product that will eventually generate billions of dollars, he said.

He said access to that CO2 could revitalize the depleted oilfields of central Alberta, adding billions of dollars to the economic benefits of both projects.

Photo: Gerald Ford

The Cenovus CO2 miscible flood project near Weyburn, Sask. In Alberta, industry is putting together the pieces of the puzzle for CO2 enhanced recovery.

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Feature

Lastmanstanding Liquids-rich, high-deliverability wells keep natural gas drilling alive in northwestern Alberta

By Darrell Stonehouse

Photo: Joey Podlubny

L

ow prices caused by a glut of natural gas supply in the United States have brought drilling and development of western Canada’s massive natural gas resources to a standstill.

Only 1,500 gas wells are expected to be drilled in 2013.

But there are some areas where gas drilling continues, and one such area is northwestern Alberta. In the northwest, a combination of high-deliverability wells and strong liquids content means drilling remains profitable.

Paramount Resources Ltd. and Trilogy Energy Corp. both continue drilling gas wells and building out infrastructure in the northwest.

Speaking at a JuneWarren-Nickle’s Energy Group Speaker Series event last fall, Paramount president and chief operating officer Jim Riddell said his company is in the midst of a major expansion of processing capacity in the northwest to handle growing production from its Montney assets. Riddell is also the chief executive officer for Trilogy.

Paramount Resources’ processing capacity will total 73,000 barrels equivalent per day once projects at its Musreau and Resthaven areas are completed, Riddell said. This would be a huge increase for Paramount, which reported average production of just under 22,000 barrels of oil equivalent per day in the second quarter.

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In Paramount’s case, Riddell discussed what the company is doing at its Resthaven/Musreau/Smoky/Kakwa areas where it is pursuing liquids-rich Montney natural gas. The company greatly expanded its presence after doing a propane frac on a vertical well, which resulted in initial production rates of between one million and two million cubic feet per day.

“We’ve now acquired over 200 sections of land in this area [and] have another 100 sections of land to the north,” Riddell said.

Horizontal wells drilled across the land base last year achieved initial rates ranging between seven million and 12 million cubic feet per day.

Because it’s a new area, infrastructure has been a priority for Paramount.

“Today we have about 15,000 barrels equivalent a day of capacity available to us. We produce somewhere in the order of 12,000 or 13,000 barrels a day,” Riddell said.

Paramount is building massive deep-cut capacity at Musreau and participating in a major expansion of the Resthaven plant’s deep-cut capacity.

“So that’s going to give us an incremental additional capacity of another 57,000 barrels equivalent a day. We’ll have a total of 73,000 barrels equivalent a day. That’s a very big deal for Paramount— Paramount produces about 20,000–25,000 barrels a day today, and we’re going to see our production double or triple over the next few years,” he said.

Meanwhile, the company is making sure it’s drilling enough wells to start filling up its new infrastructure when it comes on stream.

“We have 20 or 30 wells now drilled or completed behind pipe waiting to come on stream,” the Paramount president said.

The company previously reported the Musreau deep-cut facility is to be commissioned in the second half of 2013. Production is expected to more than double once the deep-cut Musreau and Smoky facilities are fully operational in 2014.

Regarding the growth platforms for Paramount and its affiliate, Trilogy, Riddell said all the near-term growth opportunities for both companies are in the Montney.

“I didn’t really consider us to be as much an exclusive Montney player as we really turned out to be,” he said.

Trilogy began drilling horizontal wells into the Montney at its Presley, or Kaybob South, gas play. Since 2008, the company has continued to improve its application of technology and its well results.

It began with one well per section and one frac per section. Then it went to three wells per section and seven frac stages per well for a total of 21 fracs per section. That increased to five wells per section and roughly 20 fracs per wellbore—or about 100 fracs per section, resulting in much better recoveries and economics.

Riddell said the gas wells Trilogy is now drilling are economic even at $3.50 gas.

Like Paramount, Trilogy has been steadily adding infrastructure and continues to add compression and dehydration in the field.

From a standing start in 2000, processing capacity has grown to about 85 million to 90 million cubic feet per day.

Birchcliff Energy Ltd. also continues drilling gas wells in the northwest, proving up its massive land base and driving down costs.

Birchcliff Energy has estimated a preliminary capital expenditure budget of roughly $160 million, which would be sufficient to maintain 2013 average daily production at roughly 26,400 barrels of oil equivalent per day.

In the first three quarters of 2012, Birchcliff drilled and cased 21 (21 net) Montney/Doig horizontal wells, of which 20 (20 net) wells

Feature

were completed and 19 (19 net) were on production. One (one net) of these wells was drilled since the end of the third quarter, and was a Middle/Lower Montney exploration well that continued to expand this play trend. Since the end of the third quarter, Birchcliff also drilled and cased a second vertical exploration well that appears to be successful.

Birchcliff has continued with a full-cycle exploration, exploit­ ation and development strategy for the Montney/Doig. One key element of this strategy is continued efforts on reclassifying resources from undiscovered to the discovered category and to an appropriate reserves classification. In 2012, the company drilled and cased two vertical exploration wells on lands that penetrated resources that were considered undiscovered in its 2011 year-end Montney/ Doig natural gas resource assessment. The company expects these resources will be classified as discovered resources.

It also recently drilled, cased and completed a horizontal Montney/Doig exploration well in the Middle/Lower Montney, which drilled resources considered discovered at year-end 2011, but no reserves were attributed to the particular play interval. With the successful results of this exploration well, the company expected significant reserves would be attributed to this well in its 2012 year-end reserves evaluation.

The company continues to be focused on reducing drilling and completion costs and one key initiative on the reduction of drilling costs is multi-well pad drilling. In 2012, Birchcliff drilled, cased, completed and brought production on stream for three two-well pads, one four-well pad and one seven-well pad. Currently, the company is drilling its last well of the 2012 program, which is on a two-well pad. The company continues to see cost savings with these multi-well pads.

Birchcliff believes that it has at least 1,850 net future Montney/ Doig horizontal natural gas drilling locations on its lands, based on a development scenario of four wells per section per stratigraphic play.

Also expected to drive gas drilling in 2013 is the exploration of the North Duvernay shale play.

Production from the Duvernay in a large area of northwestern Alberta is expected to reach 600 million cubic feet per day by 2020, according to a recent study.

The forecast was cited during a presentation by Bill Armstrong of Gas Processing Management Inc. and Bill Gwozd of Ziff Energy Group

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After 10 years of providing Land and Environmental services throughout BC and Alberta, we have witnessed the evolution of the energy industry. Our company has taken great pride in itself on driving regulatory policy, cooperative project planning with our clients, and the active role we play within our community.

As we move into the next 10 years, we are excited to announce a new face for BV Land and Northern Rockies. As of October 1, 2012, BV Land Consulting Ltd. and Northern Rockies Environmental Services Ltd. will be combined under our new name: BV Land Corp.

With continued service from our Fort St. John and Calgary offices, we look forward to the new opportunities and challenges the next decade will bring and are eager to share in them with our new and existing clients as well as all the folks we have met along the way.

Corporate Office: 9807-100th Avenue Fort St. John, BC V1J 1Y4 Office: 1-250-785-6340 Fax: 1-250-785-6351 Ft. St. John: 1-250-261-1802

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J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

on joint studies the two consultancies have done on natural gas and natural gas liquids (NGL) supply and infrastructure.

At a Gas Processing Association of Canada conference last fall, Armstrong and Gwozd discussed in general terms their study of what they call the north Duvernay area, which is roughly centred on the Kaybob region.

During a question-and-answer session, a member of the audience suggested the forecast of 600 million cubic feet per day by 2020 from the Duvernay “looks a little light, given all the hype around how big the play is going to be.”

In about the last three years, the industry has spent more than $4 billion on Alberta Crown land purchases believed to be targeting the Duvernay.

“It could be a whole bunch more than that,” Armstrong said, but added, “Things don’t usually develop as quickly as some people think they might. It’s a relatively conservative forecast. It’s an immature play right now.”

Armstrong said although the Duvernay resource is huge, the question is how quickly it will be developed. He noted there has been little production from the play, which is in its infancy, and that the economics—and hence the speed of development—will be influenced by the NGL content of the gas, which hasn’t yet been clearly established, as well as gas and NGL prices.

“It’ll take people a little while…to get some initial early production. And then they’ll evaluate what the economics of the play look like, and then it’ll start to ramp up—probably over another two to three years would be my guess,” he suggested.

Armstrong doesn’t expect Duvernay production from the north Duvernay study area to reach 300 million cubic feet per day before the middle of this decade.

Gwozd, who is senior vice-president of gas services at Ziff, which did the supply portion of the infrastructure studies, estimated the forecast of 600 million cubic feet per day will probably account for no more than 15–20 per cent of the total output from all formations within the north Duvernay study area.

“It’s a realistic forecast,” Gwozd said. “Some people call it conservative. But I’m very comfortable and supportive of the metrics.”

Producer spending will also affect the pace of development.

Some are putting profitability before growth, and reining in overall capital spending, which suggests fewer wells will be drilled in total in western Canada.

Gwozd cited a published comment by Hal Kvisle, the new president and chief executive officer of Talisman Energy Inc., whom the Ziff executive describes as an elder statesman of the industry: “He said he wants to get back to profitability. Not necessarily spend, spend, spend.”

Ziff Energy is forecasting 1,500 gas wells will be drilled in western Canada this year, down from a peak of about 17,000 gas wells only a few years ago.

The problem is that North American gas demand hasn’t kept pace with skyrocketing supply growth. Gwozd expects that as gas prices start to improve, producers will simply bring on production that was being held back because of low prices, thus preventing any price increase from being sustained in the long term.

So while producers obviously want to drill up the high-priced land they bought in the Duvernay—and a high yield of attractively priced NGL would boost the economics—they still need a gas price that provides an acceptable rate of return, Gwozd said.

“You can only push supply so far. You need a market pull,” he said.

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Feature

Turning on the switch Early-stage oil developments promise long-term opportunity in northwestern Alberta

By Darrell Stonehouse

T

Photo: Joey Podlubny

echnological changes have opened up new opportunities to access tight oil and bitumen resources in northwestern Alberta.

The advent of extended reach horizontal drilling and multistage fracturing has opened up tight oil reservoirs in the Montney and Dunvegan formations, along with others. Application of horizontal technologies and thermal recovery techniques are driving growth in the Peace River oilsands deposit as well.

Trilogy Energy Corp., long known as a gas producer, has been one of the pioneers of tight oil development in the northwest.

When gas prices crashed, Trilogy took its knowledge of how to develop horizontal gas wells in the Montney and applied it to oil, drilling about 21 Montney oil wells in 2011. The company drilled about 10 wells by the end of the third quarter of 2012, and planned to drill 10 more before the end of 2012, for a total of roughly 40 for both years.

“We have grown the Montney oil production from zero to 5,000 barrels per day through 2011 to probably around 10,000 barrels a day by year-end,” Trilogy chief executive officer Jim Riddell said at a recent breakfast in Calgary.

Including the acquisition of about 50 sections of land, Trilogy has spent about $300 million on its Kaybob Montney oil development and has already produced over 2.5 million barrels, Riddell noted.

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

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Shell’s bitumen operations in the Peace River oilsands. Baytex Energy and Penn West Exploration are expanding in the play.

He said the wells have “very steep” declines, coming on at 1,000–3,000 barrels per day or more, then flattening out at long-term rates of about 100 barrels per day.

Trilogy believes it can recover 100 million barrels of Montney oil over 10 years and double its production to more than 20,000 barrels per day for a recovery factor of roughly 20 per cent.

Commenting on lessons learned developing Montney gas and oil, Riddell said, “Location matters.” He said the quality of the Montney varies widely across the 350-by-50-mile fairway straddling the Alberta–British Columbia border.

“We have experience…principally in the southern part of the trend in the Alberta side of the basin, but also in northeast B.C. in some of the Paramount [Resources Ltd.] projects.”

Well orientation also matters. Riddell acknowledged there are advantages in drilling the horizontal wells in a northwestsoutheast orientation—perpendicular to the principal stress— but said Trilogy-Paramount do otherwise to be able to drill more wells without compromising the results.

“I think we have been a bit of a pioneer in not just drilling our wells northwest-southeast,” he said.

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J A N U A R Y/ F E B R U A R Y 2 0 1 3 • O I L & G A S I N Q U I R E R

The companies are also mavericks in their choice of completion fluid for the Montney. Riddell said Paramount and Trilogy are among the few producers that frac “almost exclusively” with oil rather than cheaper completion fluids.

While acknowledging that producers prefer to put oil priced at nearly $100 per barrel into sales pipelines rather than down a wellbore, Riddell said using oil as a frac fluid “gives us, so far, a better well than we would otherwise get.” He said using oil to frac produces better well results and economics, which in the long run means lower costs.

Apache Corporation is also focusing on the Kaybob area for tight oil, only in this instance, the target is the Dunvegan zone.

The Kaybob area, located 500 kilometres northwest of Calgary, contains 16 known productive horizons; the Dunvegan is one of the primary targets, the company said in December 2012.

The most recent of four Kaybob Dunvegan development wells— the 1-35—tested at a rate of 300 barrels of oil per day. The well was drilled to a vertical depth of 5,700 feet with a 4,300-foot lateral and a 13-stage fracture stimulation completion.

The first well in the campaign—the 1-9—tested at a peak rate of 280 barrels of oil per day. It was drilled to a vertical depth of 5,500 feet with a 4,900-foot lateral and 13 fracture stages.

Patrick Cassidy, director, public affairs with Apache, said that these were 30-day tests.

“This is on land purchased from BP [plc] in 2010,” he said. “With regards to future plans, we expect to increase the rigs on it.”

Future plans include ramping up drilling activity at Kaybob—the company expects to increase the rig count to four during the first quarter of 2013—and continue to access Apache Canada’s 179,000acre position (net) in the play.

“These wells were drilled in areas which have been producing for over 40 years, but which have the potential to be completely rejuvenated through the application of horizontal drilling and multistage hydraulic fracturing,” added Tim Wall, president of Apache Canada Ltd. “These encouraging results have contributed to identifying more than 2,000 potential horizontal drilling locations across our 238,000acre gross [179,000-acre net] leasehold.”

The Dunvegan is a widespread, high-quality Upper Cretaceous sandstone reservoir, the company said. A 13-stage horizontal well is expected to recover an estimated 560,000 barrels of oil equivalent.

Longer term, the Dunvegan represents a good candidate for additional production by means of secondary recovery, Apache said.

Birchcliff Energy Ltd. is also working the tight oil resource on its huge land base in the northwest. Its current focus is on the Worsley light oil resource play, which the company said “has demonstrated consistent and prolific production performance.”

“Successful expansion of the pool, waterflood performance and the application of horizontal drilling and multistage fracture stimulation technology have all contributed to its continued reserve growth, production growth and high netbacks,” it added.

In the third quarter of 2012, Birchcliff ’s activities on the Worsley play included the drilling of five (five net) horizontal wells using multistage fracture stimulation techniques. In 2012, Birchcliff drilled, cased and completed 11 (11 net) horizontal wells, all of which were successful and are on production. The company has added facility and pipeline capital in the northwestern end of the pool to accommodate the production growth in that area.

Recently, Birchcliff received approval from the Energy Resources Conservation Board to expand the waterflood area, and is currently conducting the field operations to convert wells to injection and install pipelines and related facilities.

Photo: Joey Podlubny

Feature

Feature

“These wells were drilled in areas which have been producing for over 40 years, but which have the potential to be completely rejuvenated through the application of horizontal drilling and multistage hydraulic fracturing.”

— Tim Wall, president, Apache Canada Ltd.

Birchcliff is also in the early stages of exploring other potential oil plays on its lands in the northwest.

“In our Peace River Arch core area, numerous industry competitors have announced significant developments on a number of new resource plays with a strong bias to new tight/shale oil resource plays,” the company said. “Continuing from 2011, there have been significant Crown lands posted and acquired in the Peace River Arch and numerous new wells drilled and completed targeting these new resource plays, including the Montney, Charlie Lake, Nordegg and the Duvernay.”

The Peace River oilsands are also in the early stages of a longterm development program, with Baytex Energy Corp. setting the trend. Baytex has around 320 net sections of land in the Peace River oilsands, centred around Seal. Current production is around 21,350 barrels per day.

In the third quarter of 2012, the company drilled nine (nine net) horizontal oil wells in the Seal area, encompassing a total of 116 laterals. During the third quarter, 10 wells established average 30-day

peak production rates of approximately 410 barrels per day. Six additional horizontal wells in the Peace River area were expected in the remainder of 2012.

In the Cliffdale area, successful operations continued at its 10-well commercial cyclic steam stimulation (CSS) module, with production during the third quarter averaging approximately 420 barrels, consistent with project design parameters. During the third quarter, five wells received steam and three wells commenced post-steam flowback operations. Of those three wells, two wells delivered firstcycle peak oil rates of 262 and 330 barrels per day, respectively, and one well delivered a second-cycle peak oil rate of 310 barrels per day.

First- and second-cycle steam injection volumes were encouraging and have exceeded the first-cycle injection performance demonstrated by the pilot well. Fourth-cycle flowback operations on the pilot well continued in the third quarter. Subsequent to the end of the third quarter, the final two wells commenced their initial steam injection phase. To date, the Cliffdale project has demonstrated a cumulative steam to oil ratio of approximately two barrels of steam per barrel

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

67

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of oil. Subject to receipt of regulatory approvals, Baytex plans to initiate development of a new 15-well commercial CSS module in the first quarter of 2013.

Speaking at a recent Bank of America/Merrill Lynch conference, Baytex chief financial officer Derek Aylesworth said primary recovery in the Seal area is one of the most economic plays in North America.

“Capital expenditures for an eight-leg multilateral well [are] about $2.1 million to drill, complete and equip the well. For that, we’re getting initial production rates between 400 and 500 barrels a day and ultimate recoverable [rates] in the neighbourhood of 450,000 barrels per day,” he said. “That translates to a finding and development cost of about $4.50 per barrel.

“We’ve averaged about $3.80 per barrel for an operating cost on this play largely because the wells are quite prolific, and the multilayers allow for the concentration of wells in a single surface delivery point to again minimize operating costs.”

Most of the cold production wells in the play are now being drilled with 13 laterals.

“The reason is that it is much more cost efficient, all of the horizontal producing laterals are sharing one vertical well, the cost of the one vertical well,” Aylesworth explained.

The next phase of development at Seal will be thermal developments targeting the heavier bitumen in the bottom two-thirds of the reservoir, said Aylesworth.

“The cold wells are going in the top third of the reservoir. In due course, when we’ve exhausted cold production in the top third, we’ll go back in the bottom two-thirds to extract the reserves that’s been left behind. There are parts of our land base that are not amendable to cold, i.e., the oil is too viscous, so we’re going to go directly to thermal development in those areas.”

Baytex is using cyclic steam to develop the deeper horizons. Cyclic steam injects steam into the wellbore for a period of months, and then produces through the same wellbore for a period of months.

“Our modelling suggests that, in this reservoir, we could probably have between 10 and 15 cycles per well, which implies a 10- to 15-year life of each well. So very, very long reserve life, very long productive life for this kind of development,” he said.

The latest regional business news

Business

Intelligence Getting resource estimates right ASC eyes new guidelines for booking unconventional resources

By James Mahony

How Canadian producers report unconventional oil and gas resources oft en depends on who’s doing the reporting, and the Alberta Securities Commission (ASC) would like to change that, an industry audience heard in December In the past, the reporting of petroleum resources—as opposed to reserves—has not always been consistent, and new guidelines would put producers on the same page, at least in terms of Canadian reporting standards A senior ASC executive said the commission and the Calgary branch of the Society of Petroleum Evaluation Engineers (SPEE) will work toward draft ing guidelines for evaluating unconventional resources

While these are still early days in the review process, plans include changes that will provide more guidance and accommodate more diverse product types.

“We’re proposing a partnership [between the ASC and SPEE’s Calgary chapter] that would start now and carry through until April of next year [2013],” Phillip Chan, the ASC’s chief petroleum officer and manager, told an audience of oilpatch professionals in Calgary “The deliverables and details are still being negotiated, but that’s what we’re shooting for Once draft guidelines have come out in April 2013, we’ll send them out for comment, which will take some time Our target is for a new set of guidelines for unconventional resources at the end of 2013 ” Under current rules, the disclosure of resources is not required but some producers do so, especially when it comes to unconventional resources While specifics have not been ironed out, early indications are that the draft SPEE guidelines would also include guidelines for evaluating bitumen resources To date, one of the few existing reserves models to address bitumen resources is the one developed by the United Nations, Chan said

A document familiar to most of those attending the ASC presentation on oil and gas disclosure is National Instrument (NI) 51-101, which defi nes standards of disclosure for reporting oil and gas reserves and has been adopted by Canada’s provincial-securities regulators According to Chan, NI 51-101 is being reviewed, with several changes envisioned While these are still early days in the review process, plans include changes that will provide more guidance and accommodate more diverse product types Under the current plan, the ASC will invite public comment on any proposed changes in early 2013, with implementation expected later in the year, if all goes to plan Those att ending the presentation heard that other industry committees are also considering changes that would help investors get a bett er

The interest in setting industry standards for evaluating unconven-

idea of the liabilities publicly held oil and gas producers might face down

tional resources is natural, given the evolution of the Western Canadian

the road The Petroleum Advisory Committee (PAC), for example, includes

Sedimentary Basin As recently as 2003, conventional oil and gas

representatives from the ASC and the oil and gas and investment sectors

resources made up 74 per cent of all hydrocarbon resources in the basin,

Currently, the PAC is considering guidelines for the disclosure of aban-

Chan said Yet, the figure has fallen to 40 per cent, with bitumen now

donment and reclamation issues, something that would give investors a

taking a proportionately larger share, roughly equivalent to conventional

way of assessing future environmental liability and costs arising under

resources, with shale resources making up much of the difference

the two headings The committ ee is also studying disclosure rules for

Chan briefl y discussed the Canadian Oil And Gas Evaluation Handbook

reporting undeveloped oil and gas reserves, among other topics

(COGEH), which defi nes standards for evaluating petroleum reserves As

An engineer with 40 years in the oil and gas sector, Chan is well quali-

good as COGEH is, he said it does not specifically address unconventional

fied to lead the ASC’s oil and gas professionals Before coming to the com-

resources, although that may soon change

mission, he spent 22 years at Talisman Energy Inc

O I L & G A S I N Q U I R E R • J A N U A R Y/ F E B R U A R Y 2 0 1 3

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