EXCELLENCE
IS OUR STANDARD.
Our skilled engineers understand the unique demands of Canada’s crude hauling market. Our Red Deer, Alberta location is equipped with semi trailers ranging from 38 to 46 cubic meters; quad wagons and Super B’s insulated or non-insulated. Every piece of Dragon equipment is severe duty engineered to consistently perform under punishing conditions. Nineteen state of the art manufacturing plants strategically located near the major shale plays of North America ensure Dragon can meet delivery deadlines and volume requirements virtually anywhere.
>> INSULATED BELLY BOX
>> LSAS VALVE
THE DRAGON STANDARD With Dragon, enhanced features come standard. While other manufacturers offer these options as add-on upgrades, Dragon builds them into every piece of equipment we manufacture.
Dragon will custom build a trailer to meet your individual or fleet specs and we back it up with a one year bumper-to-bumper warranty against manufacturing defect. We stand ready to support you 24/7 to keep your operation rolling. What you need. When you need it. Work with Dragon.
403.340.3600 | 213 Spruce Street, Red Deer, Alberta
dragonproductsltd.com
© Copyright 2015 Modern Group Inc. All rights reserved.
CONTENTS
JANUARY.15
in the news
9
Oilsands to contribute $3.87 trillion to Canadian GDP, says CERI
regional news
11 British Columbia
21 Central Alberta
ARC reports success with new completion technique at Tower
Trilogy focused on Kaybob
13 Northwestern Alberta
25 Southern Alberta Production growth helps drive
Birchcliff triples profit in third quarter
improved DeeThree results
17 Northeastern Alberta
27 Saskatchewan
A “citrus solution” is among three
Drilling results boost Legacy production
novel projects at heavy oil conference
Your leading service provider for oil and gas projects
features Cover Feature
Leaders of the pack Top operators in 2014 will set the trend in 2015
every issue
6
Stats at a Glance
38
Political Cartoon
The new gas giants Homegrown Deep Basin operators moving into the big leagues
We are your go-to firm for a range of services, including First Nations consultation, environmental assessment, remediation, and reclamation.
403.264.0671 hemmera.com Alberta | British Columbia | Yukon | Ontario
OIL & GAS INQUIRER • JANUARY 2015
3
Yes, they exist.
Balancing price, performance and reliability can feel like an impossible task. That’s why CG Industrial Specialties Ltd. (CGIS) has gathered best in class valve manufacturers such as Adams, Delta, Flowserve, Hy-Grade and Valvtechnologies. With CGIS, you’ll benefit from reduced maintenance, the lowest cost of ownership and the highest reliability anywhere. No matter what your application – Energy, Oil and Gas, Mining, Pulp and Paper or Water Treatment – you can rely on CGIS to provide the highest quality products and make the impossible possible.
Visit cgis.ca and discover the power of the possible.
calgary • edmonton • fort mcmurray • prince george • saskatoon • vancouver • australia • chile • russia
Editor’s Note Vol. No. EDITORIAL EDITOR
Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS
Surviving
Carter Haydu, Richard Macedo, Elsie Ross
the storm
EDITORIAL ASSISTANCE MANAGER
Tracey Comeau | tcomeau@junewarren-nickles.com EDITORIAL ASSISTANCE
Laura Blackwood, Sarah Miller, Sarah Munn, Jordhana Rempel CREATIVE CREATIVE SERVICES MANAGER
Tamara Polloway-Webb | tpwebb@junewarren-nickles.com
The quick, steep drop in oil prices the last six
increasing spending by around $90 million in 2015,
CREATIVE LEAD
months has hit the western Canadian oilpatch like
with plans to drill 37 net wells in 2015.
Cathlene Ozubko | cozubko@junewarren-nickles.com PRODUCTION COORDINATOR
Janelle Johnson | jjohnson@junewarren-nickles.com GRAPHIC DESIGNER
Peter Markiw CREATIVE SERVICES
Linnea Lapp
an early winter blizzard, freezing the industry in its tracks. Capital budgets are being cut, dividends are being slashed, and development plans reworked. But like every other pricing downturn, this
In early November, Deep Basin operator Peyto Exploration & Development announced a preliminary 2015 budget of $700 million to $750 million, the sixth year in a row that the capital budget has increased compared to the previous year.
SALES
one will end, and the market will heat up once
SENIOR ACCOUNT EXECUTIVES
again as supply issues work out. And western
124 and 137 gross wells (117–130 net to Peyto’s
Canadian operators are taking the steps necessary
working interest) utilizing nine to 10 drilling rigs.
to prosper when they do.
The 2015 drilling locations are expected to add
Nick Drinkwater, Tony Poblete, Diana Signorile SALES
Rhonda Helmeczi, Mike Ivanik, Nicole Kiefuik, Gerry Mayer, James Pearce, Blair Van Camp For advertising inquiries please contact adrequests@junewarren-nickles.com. AD TRAFFIC COORDINATOR—MAGAZINES
Lorraine Ostapovich | atc@junewarren-nickles.com DIRECTORS
The 2015 program involves drilling between
What are those steps?
between 41,000 and 45,000 boe/d of new working
Live on cash flow, manage debt to leave a
interest production.
little breathing room, and have a flexible plan in
Peyto’s main Deep Basin competitor,
place to respond to changing market conditions.
Tourmaline Oil & Gas, also has aggressive plans
Many operators, with the right assets, will con-
in place for 2015. Tourmaline plans on spend-
Bill Whitelaw | bwhitelaw@junewarren-nickles.com
tinue to grow through this winter of discontent
ing $1.4 billion across its three core areas: the
DIRECTOR OF SALES & MARKETING
and come out stronger on the other side.
Deep Basin, the northeastern B.C. Montney, and
PRESIDENT & CEO
Maurya Sokolon | msokolon@junewarren-nickles.com
Montney oil producer RMP Energy is one
the Peace River High Charlie Lake oil play. The
Ian MacGillivray | imacgillivray@junewarren-nickles.com
example of this type of operator. In mid-December,
company says it will revisit the exploration and
DIRECTOR OF THE DAILY OIL BULLETIN
RMP announced a capital budget of $150 million,
production program and the pace of activity
equal to its expected funds from operations in
during the second quarter of 2015/spring breakup
Gord Lindenberg | glindenberg@junewarren-nickles.com
2015. RMP has a borrowing limit of $175 million,
in light of the commodity price outlook at that
DIRECTOR OF CONTENT
with only $95 million drawn, leaving it plenty of
time. But as it stands, company president Mike
flexibility to respond to market changes. Despite
Rose says it’s full steam ahead.
DIRECTOR OF EVENTS & CONFERENCES
Stephen Marsters | smarsters@junewarren-nickles.com DIRECTOR OF DIGITAL STRATEGIES
Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION
Audrey Sprinkle | asprinkle@junewarren-nickles.com
planning to live on cash flow, it expects produc-
OFFICES Calgary
tion to grow by 30 per cent in 2015 to average
important to remember that Tourmaline’s natural
15,500 boe/d.
gas plays are profitable on a full-cycle basis at prices
nd Flr- Avenue N.E. | Calgary, Alberta TE Y Tel: .. | Fax: .. Toll-Free: ...
Edmonton
220-9303 34 Avenue N.W. | Edmonton, Alberta T6E 5W8 Tel: .. | Fax: .. Toll-Free: ...
MEMBERSHIPS Membership Rate In Canada, year $ plus GST, years $ plus GST Outside Canada, year $
Membership Inquiries Telephone: ... Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com
Cardium oil producer Vermilion Energy is responding to the oil price storm by switching its development focus in central Alberta to Mannville
“In this volatile price environment, I think it’s
below $3/mcf, and our oil complex is profitable full cycle at oil prices below $35/bbl,” he explains. Make no mistake, the drop in oil prices is
condensate-rich natural gas. The company expects to
going to hurt. But operators across the basin are
drill or participate in around 30 (16.7 net) Mannville
putting plans in place to survive and grow into the
wells, a nearly 50 per cent increase from 2014.
future when the market turns. There are better
Some companies focused on low cost gas plays are actually increasing capital budgets. Northeastern B.C. Montney producer Painted Pony Petroleum is
days ahead.
Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com
GST Registration Number RT. Printed in Canada by PrintWest. ISSN - | © JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number . Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return
N EXT I S S U E
to: Circulation Department, nd Flr- Avenue N.E., Calgary,
Alberta TE Y. 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.
February Heavy oil outlook, plus a review of what’s happening in the north and south Duvernay plays.
Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as ”Letter to the Editor” if you want them published.
OIL & GAS INQUIRER • JANUARY 2015
5
FAST NUMBERS
$
per barrel
Average cash costs for in situ oilsands development according to BMO Capital Markets.
$
per barrel
Average full-cycle costs for in situ oilsands development according to BMO Capital Markets.
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
OIL
GAS
Dec
Jan
Feb
Feb
Mar
Apr
May
OTHER
OIL
GAS
D RY
SERVICE
T O TA L
Dec
Jan
,
Mar
,
Apr
May
Jun
T O TA L
MONTH
Jun
Jul
Jul
Aug
Aug
Sep
Sep
,
Oct
Oct
,
Nov
Nov
,
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
Dec
Dec
Jan
Jan
Feb
Feb
Mar
Mar
Apr
May
Apr
Jun
May
Jul
Jun
Aug
Jul
Sep
Aug
Oct
Sep
Nov
Oct
Nov
*Year-to-date
OTHER
TOTAL
Features and beneFits • • • • •
Large Bore Simple Design Drop Balls Optional Rated for up to 600°F Proven Technology
• Rated for 10,000 psi (68.9MPa) • Internal Pressure Assisted Anchoring • Easily Milled if Required
24 Hour Toll-free DispaTcH: 1-855-346-9788
6
JANUARY 2015 • OIL & GAS INQUIRER
next generation “Set it & Forget it” Multistage CoMpletion dsithrutubing.com
Red deeR • CalgaRy • WeybuRn • gRande PRaiRie Houston • Minot • Midland • san antonio
wellvention.com
STATS
AT A
GLANCE
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, December 10, 2014 Source: Rig Locator
Alberta, November 2014 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
GAS WELLS
Nov
Nov
Nov
Nov
%
Northwestern Alberta
British Columbia
%
Northeastern Alberta
Manitoba
%
Central Alberta
Saskatchewan
%
Southern Alberta
%
TOTAL
WC TOTAL
Top Active Drillers in Canada
Drilling Activity: CBM & Bitumen
Western Canada, December 10, 2014 Source: Rig Locator
Alberta, November 2014 Source: Daily Oil Bulletin
O P E R AT O R
ACTIVE RIGS
DEV
C OA L B E D M E T H A N E
EXP
Canadian Natural Resources
Tourmaline Oil
Progress Energy Canada
Cenovus Energy
Encana
Seven Generations Energy
ConocoPhillips Canada
Husky Energy
Paramount Resources
Apache Canada
Alberta
BITUMEN WELLS
Nov
Nov
Nov
Nov
Northwestern Alberta
Northeastern Alberta
Central Alberta
Southern Alberta
TOTAL
www.bcri.ca Our team of scientists and engineers are ready to bring your
IDEA
chemical products and processes PROOF FEASIBILITY OF CONCEPT STUDY Custom Research
Preliminary Engineering
PILOT PLANT
COMMERCIAL SCALE
Design, Construction and Operation
Detailed Engineering
from concept to commercialization
OIL & GAS INQUIRER • JANUARY 2015
7
IN THE
NEWS Issues affecting Canada’s E&P industry
Oilsands to contribute $3.87 trillion to Canadian GDP, says CERI By Elsie Ross
Between 2014 and 2038, Alberta oilsands investment, re-investment and operating revenues will contribute an estimated $3.87 trillion to the Canadian gross domestic product (GDP), says a new study from the Canadian Energy Research Institute (CERI). Oilsands production (upgraded and non-upgraded) over that period is forecast to grow to 3.7 million bbls/d by 2020 and 5.2 million bbls/d by 2030, according to the report on the Canadian economic impacts of oilsands development in Alberta. The study, an update of a 2011 report for the 2010-35 period, concludes that the total investment in new Alberta oilsands projects and re-investment (sustaining capital) in existing oilsands projects will exceed $514 billion (2013 Canadian dollars)
by 2038. Revenues from all existing and new projects will exceed $2.48 trillion in that period, it estimates. CERI considers the numbers to be conservative as the report is based on US$85/bbl WTI oil, Peter Howard, CERI chief executive officer, said. When researchers were working on the report this past summer, the figure was seen as the most conservative view of the economic potential of the oilsands, he said. Although the study includes some projects that have been announced, the majority are either on production, under construction, approved and waiting to start construction or waiting to go to the regulator, he said. Changes in how Statistics Canada collects data on the oilsands, including
CERI believes oilsands production will reach 5.2 million bbls/d by 2030.
separating oilsands operations from the mining and extraction sector, resulted in a different view of the impact of the oilsands across the country, said Howard. “One of the big deals—other than the big dollars— is that 11 per cent of the GDP impacts are felt outside Alberta—double what the previous report said.” In Alberta, oilsands-related direct employment is expected to continue growing to a peak of 256,000 jobs in 2024 from the current level of 146,000 jobs. The numbers include jobs in on-site construction, ongoing and turnaround maintenance, offsite prefabrication and modular construction, as well as SAGD and cold bitumen well development. For every direct job generated in the Alberta oilsands, one additional job is generated by indirect association and 1.5 jobs by induced association, Howard noted. “And all those jobs are in Canada.” Total Canadian employment (direct, indirect and induced) related to the oilsands is expected to continue growing to a peak of 802,000 jobs in 2028 from the current 2014 level of 514,000 jobs as a result of construction of new projects, and the operation of new and existing projects. “This assumes that rail and pipelines will be developed in timely fashion,” he said. Indirect jobs account for the potential of jobs created in the many industries across Canada that serve the oil industry, including manufacturing in Ontario, pipeline mills in Saskatchewan and Alberta, and electronic components in B.C., Ontario and Quebec. Induced job effects account for workers in the oilsands sector spending their additional income on consumer goods and services. The CERI update calculated that after accounting for annual operating and maintenance costs above new and sustaining OIL & GAS INQUIRER • JANUARY 2015
9
In The News
capital, the total cost requirement for the oilsands industry will grow to a high of $67 billion in 2017 and average $55 billion annually for the duration of the forecast. Those numbers are not out of line, as the Canadian Association of Petroleum Producers has estimated that the oilsands industry invested $52 billion in 2013, said Howard.
Governments also will benefit from the growth in oilsands activity through taxes and royalties, the CERI report concludes. It estimates that oilsands-related taxes directed to the Canadian federal government will total $574 billion (2013 Canadian dollars), while the A lberta government will take in a total of $302
billion in oilsands-related taxes, excluding royalties. Oilsands royalties paid to the Alberta government are forecast to grow to $18.2 billion by 2023 from $4.4 billion in 2013 with the cumulative total to be collected by the government exceeding $600 billion over the next 25 years.
CAODC predicts 10 per cent fewer wells in 2015 The Canadian Association of Oilwell Drilling Contractors (CAODC) has released its 2015 drilling activity forecast, which projects a 10 per cent decrease in activity from 2014. Canadian land-based drilling rigs will drill 10,354 wells in 2015. This well count will generate 119,578 operating days for land-based drilling contractors based on spud to rig release data. T he uncer taint y around pipeline construction was a determining factor in the activit y outlook, the industr y group stated. Each active rig generates between 135 and 200 direct and indirect jobs, but this economic activity is currently limited due to the inability of the Canadian industry to access overseas markets. “The B.C. government is weighing decisions that will have significant impact on industry activity. The current uncertainty has been factored into this forecast. If a direction is established regarding pipeline construction or LNG terminals, then we will defi nitely revisit these projections,” said Mark Scholz, president of the CAODC.
Quarter
Active Rigs
Fleet
Utilization
Operating Days*
- st
493
809
61%
42,403
- nd
154
810
19%
14,082
- rd
333
811
41%
30,090
- th
374
813
46%
33,003
Average
338
811
42%
Total: 119,578
Assumptions: WTI: US$85/bbl; AECO: C$4/mcf; 11.5 days/well *Calculation based on spud to rig release data.
The Petroleum Services Association of Canada recently forecast a total of 10,100 wells drilled (rig released) across Canada for 2015, a slight decrease from the expected fi nal tally of 10,830 rig releases for 2014. In its forecast, the CAODC pointed out that drilling activity follows a specific annual cycle. Rig utilization and operating days are highest in the first quarter. The second quarter drops due to spring breakup. The third quarter sees strengthening activity, and the fourth quarter trends higher still as cold weather opens more opportunity.
Source: CAODC
CAODC anticipates that rig utilization in 2015 will average out to 61 per cent in the fi rst quarter, 19 per cent in the second quarter, 41 per cent in the third quarter and 46 per cent in the fourth quarter. For 2014, utilization is expected to average 46 per cent, with an expected average of 42 per cent for 2015. The CAODC-registered fleet will begin 2015 with 809 rigs. It is estimated that the CAODC-registered land-based drilling fleet will grow slightly and finish 2015 with 813 rigs. The forecast assumes a WTI price of US$85/bbl, an AECO price of C$4/mcf and an average 11.5 days per well.
“Where Service Comes First”
Internal & External Tank, Vessel and Pipe Coating In the Field or at our Facilities, NO job is too big 6415 Wildrose Drive Taber, AB T1G 1Z4 1 (888) 223-4016 www.artechcoating.com
Visit us at the Global Petroleum Show – Booth #4218
10
JANUARY 2015 • OIL & GAS INQUIRER
B.C.
BRITISH COLUMBIA WELL ACTIVITY NOV/13
NOV/14
Wells licensed
162
NOV/13
NOV/14
Wells spudded
67
NOV/13
NOV/14
59
Rigs released
▲
▲
British Columbia
▲
Source: Daily Oil Bulletin
ARC reports success with new completion technique at Tower ARC Resources attributes strong well performance at its 05-14 and 08-15 pads at Tower to a new completion technique involving the application of a slickwater frac with tighter inter-frac spacing and more sand tonnage per well, while previous Tower wells were completed with a hybrid slickwater frac. Production results to date from seven of the nine wells on the 08-15 and 05-14 pads exceed the best results from the 12-16 pad, which came on stream in the second quarter of 2014. Results to date at Tower, where 36 wells are currently on production, have been exceptional, said ARC. During the third quarter of 2014, ARC brought on stream the 08-15 pad (a fi vewell pad expansion) and the 05-14 pad (a four-well pad expansion). Six of the nine wells on the 08-15 and 05-14 pads have been on production for more than 60 days. A RC repor ted st rong product ion results: the 60-day average rates for the individual wells range from 600 to 1,100 boe/d, comprised of 400–900 bbls/d of oil and one to two mmcf/d of gas.
Total cumulative oil production from all nine wells exceeded 380,000 barrels of oil based on individual wells on production for a range of 36–84 days. ARC’s production of 115,530 boe/d hit a new record during third-quarter 2014 thanks to new wells at Parkland/Tower coming on stream and new wells brought on production at Sunrise through a thirdparty facility. Its capital program focused on highrate-of-return oil and liquids development at Parkland/Tower, Ante Creek, Pembina and southeastern Saskatchewan, and lowcost, high-rate-of-return natural gas development at Dawson and Sunrise. ARC had an active third quarter of 2014, drilling 56 gross operated wells: 48 oil wells, three liquids-rich gas wells and five natural gas wells. In the first nine months of 2014, the company drilled 153 gross operated wells: 109 oil wells, 19 liquids-rich gas wells and 25 gas wells. Record crude oil and liquids production of 44,789 bbls/d (39 per cent of total production) was 23 per cent higher than the third
ARC Resources capital budget Gross wells1 Region
Budget ($ millions)
Oil
Liquids- Natural rich gas gas
Other
Total
Northeastern B.C.
425
19
6
17
2
44
Northern Alta.
205
29
3
0
0
32
Pembina
105
32
0
0
0
32
South Central Alta.
20
2
0
0
0
2
SE Sask./Man.
100
30
0
0
1
31
Total
1. Includes operated and non-operated. 2. Excludes land expenditures and minor net property acquisitions, which are unbudgeted.
Core areas Parkland/Tower, Sunrise, Dawson Ante Creek, Pouce Coupe Cardium Redwater Goodlands, other
Source: ARC Resources
quarter of 2013 due to significant growth at both Ante Creek and Parkland/Tower since the third quarter of 2013 as new production was brought on stream to fill new facilities. Crude oil and liquids production has increased approximately 40 per cent since 2010 due to a deliberate focus on highvalue oil and liquids-rich gas development, which started in 2011. ARC continues to optimize its asset base, growing its presence in key areas through land purchases and tuck-in acquisitions and divesting of non-core assets. During the first nine months of 2014, ARC added approximately 70 net sections of lands, primarily in the Montney region of B.C. and Alberta, and divested 2,400 boe/d of non-core shallow gas assets in April 2014. ARC expected annual average production to be approximately 11,000 boe/d in 2014.
B.C. land sale delivers $209.56 million By Richard Macedo
A pair of parcels that combined for $190.46 million was largely responsible for the $209.56 million in bonus bids collected by the B.C. government at its November land sale. In terms of single sales, the sale is the 11th best of all time in B.C. Industry purchased 28,836 hectares at an average price of $7,267.19. Year-to-date, the province has collected $344.77 million on 126,598 hectares at an average of $2,723.36. The government has now surpassed its bonus revenue for all of 2013 of $224.68 million, with one sale scheduled for December. Its yearly record was $2.66 billion, which was set in 2008. The land sale bonus high of $123.65 million was submitted by Charter Land Services, which acquired an 8,350-hectare licence. It included four tracts and several OIL & GAS INQUIRER • JANUARY 2015
11
British Columbia
sections in the area around 87-25W6, 88-25W6 and 94-A-12. Windfall Resources paid $66.81 million for a 3,710-hectare licence. It also included four tracts and several units at 94-A-12 and 94-B-09. These bonuses resulted in the two highest per-hectare bids: $14,808 and $18,008 per hectare, respectively. These parcels appear to have been purchased for their Montney potential, said Brad Hayes, president of Petrel Robertson Consulting. “Many of the tracts had all rights posted, but some were posted for deep
rights below Artex/Halfway/Doig, pointing at the Montney as the key zone,” he said. “There are several horizontal wells producing from the Montney in nearby offsetting areas.” These lands lie in the structured outer Foothills area of northeastern B.C., offsetting Kobes, Townsend and Blueberry structures. “The interesting thing here is that most of the lands appear to lie off of the main structural trends where most wells have been drilled, indicating that the successful purchaser feels that the Montney reservoir can be adequately stimulated with horizontal wells and hydraulic fracs without
relying on natural fracturing to enhance reservoir quality,” Hayes said. Steve Hager, senior exploration analyst with Canadian Discovery, noted that these two large parcels, which include a mix of petroleum and natural gas rights mostly from surface to basement—but in all cases include the Triassic Montney—are located on trend southeast of the large North Montney liquids-rich gas resource play, which is centred in the Town Field. Progress Energy Canada along with Royal Dutch Shell plc and Painted Pony Petroleum are leading the development of the North Montney play.
Storm to up spending in 2015 Montney developer Storm Resources plans capital spending of $110 million in 2015, excluding acquisitions and dispositions. The company also increased its estimate of 2014 capital spending (excluding acquisitions and dispositions) to $105 million from its May guidance of $97 million. Total 2014 capital spending was expected to total $193 million, including $88 million for acquisitions. The $8-million increase in field capital in 2014 includes $3.5 million to buy equipment to expand the second field compression facility at Umbach, in northeastern B.C., and $4.5 million to drill an additional two horizontal wells. Fourth-quarter production was forecast at 14,000–14,500 boe/d. Full-year 2015 production is forecast at 11,500–12,700 boe/d, which assumes Umbach South is shut in for about three weeks during June 2015 for a scheduled maintenance turnaround at
12
JANUARY 2015 • OIL & GAS INQUIRER
the McMahon gas plant. This will reduce Storm’s production in the second quarter of 2015 to about 10,400 boe/d. The 2015 budget includes the drilling of nine horizontal wells at Umbach and 14 completed and tied-in wells. At Umbach South, $41 million will be invested to further expand infrastructure, including $2.5 million for pipelines, $9.5 million to expand the second field compression facility, $4.9 million for a condensate stabilizer plus other equipment at the second field compression facility and $24 million to construct a third field compression facility. Production at Umbach, where thirdquarter output was 5,823 boe/d, was up 168 per cent from a year ago and 46 per cent from the previous quarter. Natural gas liquid (NGL) production was 1,154 bbls/d, a year-over-year increase
of 554 boe/d, or 92 per cent. Increased NGL production was the result of production growth from the liquids-rich Montney Formation at Umbach where recovery was 39 bbls per mmcf in the third quarter. With 62 per cent of the NGL mix being condensate plus pentanes, the NGL price of $73.09/bbl was 75 per cent of the average Edmonton Par light oil price. Activity was focused on Storm’s 100 per cent working interest (WI) lands at Umbach South where three Montney horizontal wells (three net) were drilled, three horizontal wells (2.6 net) were completed and the new field compression facility was started up ahead of schedule on August 19. To date in 2014, seven horizontal wells (6.6 net) have started producing at Umbach, increasing Storm’s overall production to more than 10,500 boe/d in October—up from 5,068 boe/d in the first quarter, the company said.
NORTHWESTERN ALBERTA WELL ACTIVITY NOV/13
NOV/14
Wells licensed
296
NOV/13
NOV/14
Wells spudded
238
NOV/13
NOV/14
199
Rigs released
▼
▲
▼
Source: Daily Oil Bulletin
N.W. Northwestern Alberta
Birchcliff triples profit in third quarter Despite being heavily natural gas weighted, Birchcliff Energy almost tripled its net earnings and delivered record quarterly production in the third quarter of 2014. Production for the quarter consisted of about 84 per cent gas and 16 per cent oil and natural gas liquids. Operating costs were at a record low of $5.06/boe, down 11 per cent from $5.66/boe in the third quarter of 2013. This largely reflected the savings achieved from processing more gas through the Pouce Coupe South (PCS) plant. In the first nine months of 2014, net operating costs for gas processed at the PCS plant averaged 40 cents/mcfe ($2.40/boe) and the estimated operating netback for Birchcliff ’s gas production flowing to the PCS plant was $4.55/mcfe ($27.27/boe), achieving an operating margin of 82 per cent. Also, the volume of high-value liquids recovered at the PCS gas plant, which are primarily condensate, has increased significantly to eight bbls per mmcf from 4.9 bbls per mmcf in the comparable nine month period of 2013. Birchcliff continues to aggressively delineate the Montney/Doig gas resource play both geographically and stratigraphically. To date, the company has concentrated on two intervals of the play—the Basal Doig/Upper Montney interval and the Middle/Lower Montney interval. Birchcliff has recently successfully drilled its first horizontal well in a new Montney interval in Pouce Coupe, known as the Montney D4. The company said initial production rates exceeded expectations for Montney/Doig horizontal gas wells. This drilling success in the Montney D4 is expected to add significant Montney D4 reserve bookings at the end of 2014 as there were no reserves previously booked to this interval.
Birchcliff said the Montney D4 interval is prospective over its Pouce Coupe land base where the company has existing infrastructure and its scalable PCS gas plant. The company said this infrastructure will result in significant development efficiencies and cost savings as it develops this new Montney D4 interval. The Elmworth/Sinclair area has seen significant recent industry activity including a number of successful Montney/Doig horizontal wells directly offsetting and on trend with Birchcliff ’s Montney/Doig horizontal well development program. Birchcliff recently drilled its first Montney/ Doig horizontal gas well in the Elmworth/ Sinclair area in the Montney D4 interval.
, Birchcliff ’s net future drilling locations
In addition, Birchcliff had previously drilled three vertical stratigraphic tests in the Elmworth/Sinclair area that have helped delineate the potential of the Montney/Doig play in this area. Initial production rates exceeded the company’s expectations for Montney/Doig horizontal gas wells. Birchcliff expects its exploration drilling success in the Montney D4 at Elmworth/Sinclair to add significant reserve bookings at the end of 2014, as no reserves were previously booked to this interval. Birchcliff owns 307.6 net sections that have potential for the Middle/Lower Montney play, and 287.4 net sections that have potential for the Basal Doig/Upper Montney play. On full development of four horizontal wells per section per play, Birchcliff
has 2,380.2 net existing horizontal wells and future horizontal drilling locations. With 145.9 net horizontal locations drilled to September 30, the company said there remain 2,234.3 net future horizontal drilling locations on these two plays. The Montney D4 drilling success in Pouce Coupe and Elmworth/Sinclair areas adds a new interval to the company’s Montney/Doig play and significant future drilling opportunities as the company currently holds 319.1 (307.6 net) sections of Montney rights. Birchcliff believes it now has 3,464.7 net future drilling locations, up from 2,234.3 net future locations, in its three intervals that have been proven commercial on its Montney/Doig play. The Phase 4 expansion of the PCS gas plant is complete and as a result processing capacity has increased to 180 mmcf/d from 150 mmcf/d. The estimated cost of the Phase 4 expansion was about $11.6 million. The project was completed on schedule and on budget. Engineering, procurement and fabrication work is underway for the Phase 5 expansion of the PCS plant, which will increase processing capacity to 240 mmcf/d with an expected start-up late in the fourth quarter of 2015. Preliminary planning and permitting work has been initiated for the Phase 6 expansion of the plant that will increase processing capacity to 300 mmcf/d with start-up currently being planned for late 2016. Focusing on improving capital efficiency, the company is using multi-well pad drilling in its Montney/Doig play to improve drilling and completion efficiencies and reduce the cost per well. The reduction in drilling and completion costs is significant. As well, pad drilling allowed Birchcliff to drill continuously through spring breakup, improving capital efficiency. OIL & GAS INQUIRER • JANUARY 2015
13
Northwestern Alberta
T he compa ny ha s now succe s s fully drilled and cased 153 (152.9 net) Montney/Doig horizontal wells, using the latest multistage fracture stimulation technology. Birchcliff currently has four drilling rigs working. Three rigs are drilling Montney/Doig horizontal gas wells, and
one rig is currently drilling a Charlie Lake horizontal light oil well in the Progress area. Birchcliff is at various stages of drilling, completing and tying in the remaining wells in its 2014 drilling program. The company had 13 horizontal wells to bring on production before the end of 2014, including 12 Montney/Doig horizontal gas
wells and one Charlie Lake horizontal light oil well. Production for 2014 was expected to average 34,000 boe/d, up 32 per cent from 2013. Fourth-quarter production was expected to average 38,000 boe/d and the company expected to exit 2014 at about 40,000 boe/d.
NuVista announces 2015 capital program of $340 million to $380 million The board of directors of NuVista Energy has approved a 2015 capital program of between $340 million and $380 million. That compares with 2014 guidance of $310 million to $320 million. NuVista reported higher cash f low and revenue in the third quarter of 2014, but production was down marginally and the company sustained a tiny net loss. The 2015 capital program includes up to $275 million for development and
delineation drilling, completions and tieins of about 29 wells; $55 million for the Elmworth block compressor station and trunk pipelines; and up to $40 million for long-term permanent water supply, treatment and disposal facilities, as well as land, seismic and overheads. This program allows the company to balance short-term growth while continuing to lay key foundations for significant long-term growth.
NuVista also planned to continue its asset rationalization program with the same annual target of between $25 million and $50 million in 2015 divestiture proceeds to help fund Wapiti Montney growth. The company said it has significant flexibility and opportunity to accelerate the Wapiti program as 2015 progresses. But given the current commodity price uncertainty, it chose a conservative approach as it monitors future drilling results along with prices.
• 3750L transportable Meridian Fuel Express Fuel Trailer (TC rated) • 40 GPM pump for fast refueling times • 50’ x 1” hose/nozzle/hose reel • 208L DEF sys. 12v pump/25’x3/4” hose/nozzle/hose reel • 2 large sealed cabinet doors for easy access • Optional rear utility box • Structural tubular frame & powder coat finish for durability & longevity • Design carries a low center of gravity for smooth and stable tracking ®
Contact us today at 1-800-661-1436, or visit www.meridianmfg.com. © 2014 Meridian Manufacturing Inc. Registered Trademarks Used Under License.
14
JANUARY 2015 • OIL & GAS INQUIRER
www.meridianmfg.com
Northwestern Alberta
NuVista expects 2015 production to be in the range of 23,500–25,000 boe/d, a 35 per cent increase from absolute 2014 reported average production, or a 50 per cent increase after adjusting for announced 2014 asset dispositions with associated production of 2,200 boe/d. Current output is 23,500 boe/d. This represents 21,500 boe/d net of the previously announced asset divestitures, which took effect in the fourth quarter of 2014. NuVista said its 2015 capital program meets five strategic goals: • To continue development drilling in its Bilbo block and ramp up production in the new Bilbo facilities; • To replace, through Montney development spending, the production of 2,200 boe/d from assets recently sold; • To build another large compressor station in its Elmworth (North) block of the same size and design as its Bilbo station. This will ultimately underpin significant 2015-17 Elmworth facility capacity growth of another 80 mmcf/d and 4,800 bbls/d of condensate. This
NuVista IP Montney well results Raw gas (mmcf/d)
Condensate (bbls/d)
Total sales (boe/d)
CGR condensate raw gas (bbls/mmcf)
Bilbo Development Typecurve
5.8
435
1,356
75
Well 22 - Bilbo Dev. /---W/
4.3
405
1,077
93
Well 23 - Bilbo Dev. /---W/
4.6
712
1,379
156
Well 24 - Bilbo Dev. /---W/
7.8
611
1,760
78
Well 25 - Bilbo Dev. /---W/
4.9
331
1,087
67
Location
Well 26 - Bilbo Dev. /---W/ Well 27 - Bilbo Dev. /---W/ Well 28 - Bilbo Dev. /---W/
4.2
268
916
64
8.3
512
1,740
61
7.9
578
1,770
74
Montney Delineation Typecurve
5.8
261
1,222
45
9
236
1,694
Well 29 - North Montney Delineation /---W/
26
Source: NuVista Energy
capacity growth represents a tripling of NuVista’s facility capacity compared to fi rst-quarter 2014. With the addition of the Elmworth compressor station, total NuVista Montney facility capacity will reach over 40,000 boe/d by mid-2016;
• To continue the successful development drilling program in its Elmworth block; and • To continue t he single-rig Wapiti Montney rolling delineation and land continuation program.
16
th
JUNE 3 & 4, 2015
biennial
eXHibition Grounds | weYburn, sK
Nominations are now being accepted for the 2014 Southeast Saskatchewan Oil Person of the Year form available to download on our website
SPONSORS
PLATINUM
GOLD
CONTACT US PHONE: [306] 842-3232 FAX: [306] 842-3265 EMAIL: sk.oilshow@sasktel.net WEBSITE: oilshow.ca
OIL & GAS INQUIRER • JANUARY 2015
15
ExpEriEncE counts. new buildings are a major investment. we streamline the process by giving you a single point of contact. we estimate costs sooner providing you with greater financial control. we use proven building systems to reduce your build time.
ovEr 40 yEars of DEsign | BuilD ExpEriEncE working for you. w w w . s c o t tbuilders.com tbuilders.com www.scot
NORTHEASTERN ALBERTA WELL ACTIVITY NOV/13
NOV/14
Wells licensed
153
NOV/13
NOV/14
Wells spudded
94
NOV/13
NOV/14
106
Rigs released
▲
▼
▼
Source: Daily Oil Bulletin
N.E.
Northeastern Alberta
A “citrus solution” is among three novel projects at heavy oil conference By Carter Haydu
US Oil Sands’ use of a by-product from orange juice manufacturing to separate bitumen could change the way minable oilsands are developed, said a company executive. “We think this opens up an opportunity to develop smaller deposits that just are not feasible under some of the 100,000-bbl/d projects we see right now in Athabasca,” vice-president of operations Barclay Cuthbert said. “We feel that once we have our first project up and running, it really will open the door to further development, both in Utah and around the world, as well as back here in Alberta.”
Using citrus oils to separate bitumen could work at small developments, says US Oil Sands.
The US Oil Sands development was one of three projects for which companies provided updates during a session of the Canadian Heavy Oil Conference. A Canadian-based company developing the fi rst-ever oilsands project to commercially extract U.S. bitumen from its 100 per cent interest in bitumen leases covering 32,005 acres in Utah, US Oil Sands uses citrus oils in an innovative way to remove the need for costly, longterm tailings, as well as allowing for much faster remediation. The company recently ordered all major equipment components required for construction of the PR Spring Project, committing roughly US$17.9 million to the purchase of this equipment, engineering and site construction, while remaining on schedule for third-quarter 2015 field commissioning. “Over last year and this year, it has really been about execution,” Cuthbert told the conference. “We have our project, it has been approved by a board of directors and we are into construction with fi rst oil expected in October of [2015].” When the company builds its 2,000bbl/d demonstration facility to prove the technology, he added, the main measures of success would be if there is good oil and solvent recovery, while keeping within the $60-million project budget as well as limiting the tailings. Based on that success, the company would move toward a 10,000bbl/d project. “Once we have the first unit up and running, we will be able to move very quickly into a Phase 2 development,” he said. According to Cuthbert, the technology lends itself to smaller-scale developments, meaning there are lower upfront capital
requirements, and therefore companies would be taking less risk on any individual project as opposed to a typical oilsands surface mine. Furthermore, the technology is more efficient than the traditional methods, operating at about one-third the capital costs per flowing barrel, he said. On the environmental front, he noted, because there are no liquid tailings the process has a small land footprint. The company reuses water, which reduces its impacts in that regard as well. Also, reclamation can occur simultaneously with project development. Cuthbert said, “Because we are able to dry those tailings, and they are stackable, we can put them back into our mine immediately as we deplete areas of the oilsands resource.”
Grand Rapids, Grosmont player Laricina examining options Leading-edge bitumen developer Laricina Energy reported an average production of 907 bbls/d in the third quarter of 2014, up from 402 bbls/d in the corresponding 2013 period. Since it is still in start-up mode, Laricina reported negative cash flow for the first nine months of 2014. Third-quarter output of 907 bbls/d consisted of 674 bbls/d from Laricina’s Germain commercial demonstration project, which is in the largely untapped Grand Rapids OIL & GAS INQUIRER • JANUARY 2015
17
Northeastern Alberta
Chase Operator Training offers safety training on all Power Mobile Equipment from Aerial Platforms to Zoom Boom Forklifts. Train the Trainer Available. Equipment Rentals now available on Zoom Boom Forklift and our new Spyder Crane.
1-800-317-3612
|
info@chaseot.com | chaseot.com
OvEr
Pressure Vessels By
PENFABCO LTD.
vEssELs BuiLT TO DATE
Separators Dehydrators Treaters FWKOs Scrubbers Swab Vessels Line Heaters Steam Splitters Coil Rolling Drip Pots External Level Cages Filter Vessels
5715-56 Avenue, Edmonton, Alberta | p: 780.434.0222 | f: 780.436.1467 | e: info@penfabco.com
www.penfabco.com
18
JANUARY 2015 • OIL & GAS INQUIRER
sands, and 233 bbls/d from its pilot at Saleski, which produces from the bitumenbearing Grosmont carbonates. There has never been large-scale commercial production from the vast bitumen resource stored in carbonate formations in Alberta. But before large-scale commercial production can occur at either Saleski or Germain, Laricina said it will need “significant financing.” “We have been actively monitoring the capital markets since 2012. However, conditions have not been favourable for a conventional financing. Our future projects will be delayed unless we are able to raise additional funds,” Laricina said in releasing its third-quarter results. Privately held Laricina said it has hired financial advisers “to assist us in examining and pursuing the full range of alternatives.” The Canada Pension Plan provided Laricina with $250 million in equity financing in 2010 and $150 million in debt financing earlier in 2014. Laricina said Germain’s September production averaged 726 bbls/d of bitumen from four of the 10 original well pairs. Six need to be re-drilled if the money can be found to pay for it. Germain is still in ramp-up mode—the project’s design capacity is 5,000 bbls/d. Well pairs seven through 10 have producers in the bitumen zone. Well pairs one through six have producers in the basal water zone. As discussed in its second-quarter results, Laricina determined that the basal-water-zone well pairs are impeded by a thin tight streak of mudstone between the producer and injector wells, creating a barrier to the flow of bitumen. As a result, well pairs three, five and six did not achieve the expected production response and have been shut in. In the third quarter, the company received regulatory approval to re-drill six basal-waterzone well pairs above the tight streak and a program has been developed. Laricina said the re-drills are an important part of its overall development strategy at Germain, but more financing is needed before it can proceed. Compared to the Clearwater Formation in the Cold Lake oilsands region and the McMurray Formation in the Athabasca oilsands region, there has been almost negligible production from the Grand Rapids Formation. One Grand Rapids producer is Canadian Natural Resources’ (CNRL’s) Wolf Lake SAGD project, which was started
Northeastern Alberta
by BP Amoco in 1997 and later acquired and expanded by CNRL to about 5,000 bbls/d. Although eight well pairs were drilled at Germain, only four well pairs are now producing. Well pair seven was the last to be converted to production late in the third quarter of 2014. Well pair nine began producing in the fi rst quarter and well pairs eight and 10 began producing during the second quarter. Laricina plans to use solvent-cyclic SAGD at Germain. Injecting solvent with steam is meant to increase bitumen production while decreasing steam requirements. In the third quarter of 2014, the company began solvent injection in well pair 10. “Although results are preliminary, we have seen a 20 per cent increase in production volumes and a reduced SOR [steam to oil ratio],” Laricina said. In the fourth quarter of 2014, the company began solvent injection in well pair eight, followed by well pairs nine and seven. Regarding the next phase planned for Germain, Laricina expected to submit its response to a third supplemental information request from the Alberta Energy Regulator by the end of 2014.
“Our future projects will be delayed unless we are able to raise additional funds.”
PROVIDING INDUSTRIAL ENERGY SERVICES SINCE 1953
PLANT & FIELD MAINTENANCE
SHUTDOWNS
CONSTRUCTION
FABRICATION
W W W. TA R TA N . C A
— Laricina Energy
The company said it expects to receive regulatory approval for the Germain expansion in early 2015. In the third quarter, the focus at the Saleski pilot was on the Grosmont D and understanding how best to drill and operate in the D zone to maximize production and ultimate recovery. The company said 3D, the most recently drilled well at the pilot, began its third production cycle near the end of September. The well is intended to help understand and verify D-zone performance in an undisturbed part of the reservoir. Laricina said the most recently drilled well in the D zone continues to demonstrate production and SORs that complement C zone production and SORs, demonstrating that the Grosmont can be competitive with average McMurray in situ projects. “While early in production testing, results thus far from the 3D well—along with existing pilot data—support our commercial average per well target of approximately 250 gross bbls/d of bitumen production from the D zone,” the company said. Designed to improve on conventional SAGD, the Saleski pilot configuration was later changed to use only a single horizontal well, in alternating cycles, to inject steam injection and produce bitumen—a technique called cyclic SAGD. The C-zone wells at Saleski produced until the end of September, and then 2C and 1C-s returned to steaming. In both the C and D zones, Laricina has been testing an artificial lift system for pump performance in certain reservoir operating conditions. The progressive cavity pump was replaced with a more robust electric submersible pump (ESP) in 1C-s. Laricina said early ESP performance has exceeded expectations and it expects to have the full range of operating conditions tested by late 2014.
YEAR ROUND INDUSTRIAL & COMMERCIAL INSTALLATION • Chain Link Fence and Gates • Electric Gate Operators & Access Controls • Pre-Manufactured/Portable Site Enclosures • Industry Leading Health, Safety & Environmental Program
We also offer Safety Fence, T-Posts, Ornamental Fence & Vinyl Fence EDMONTON
(780)447-1919
12816 - 156 St. Fax: (780) 447-2512 edmonton@phoenixfence.ca
1-800-661-9847
CALGARY
(403)259-5155
6204 - 2nd St. S.E. Fax: (403) 259-2262 calgary@phoenixfence.ca
1-888-220-2525
OIL & GAS INQUIRER • JANUARY 2015
19
CENTRAL ALBERTA WELL ACTIVITY NOV/13
NOV/14
Wells licensed
205
NOV/13
NOV/14
Wells spudded
193
NOV/13
NOV/14
196
Rigs released
▼
▼
▼
Source: Daily Oil Bulletin
C.A.B. Central Alberta
Trilogy focused on Kaybob
Higher gas prices resulted in Trilogy focusing on Montney gas in the third quarter.
Trilogy Energy’s third-quarter activity was focused mainly in the Kaybob area where it drilled 17 (11.8 net) wells horizontally into different formations. During the third quarter of 2014, Trilogy spent $81.1 million on drilling, completions, production facilities, and corporate and land acquisitions, compared to $174.3 million spent in the fi rst quarter and $111.9 million in the second quarter of 2014. Capital spending to the end of the third quarter of 2014 totalled $367.39 million. Capital spending in 2014 was primarily directed toward Trilogy’s Montney oil and gas pools, and Duvernay operations in the Kaybob area. Trilogy anticipated spending approximately $63 million in the fourth quarter to drill three Montney oil wells, complete wells that were drilled in the prior quarters, and participate in thirdparty drilling and completion operations. The company’s drilling operations during the third quarter of 2014 were primarily
focused in the Kaybob area, where the company participated in the drilling of 17 (11.8 net) wells. These wells were drilled horizontally into a number of different formations. Of these wells, 11 Trilogy-operated wells were targeting the Montney for oil and natural gas, the Gething for crude oil, and six non-operated wells were drilled for Cardium and Dunvegan oil and Notikewin natural gas. Through the balance of the year, Trilogy plans to continue to focus its capital spending on oil, condensate and liquidsrich gas plays in the Gething, Montney and Duvernay formations where the company has developed the expertise to fi nd, develop and produce the reserves at very attractive economic returns. Trilogy will continue to evaluate other formations to ensure that its capital allocation is directed to plays that provide the best economic return and strategic value. During the third quarter, Trilogy drilled seven (seven net) wells to further develop
the Kaybob Montney oil pool, bringing the total number of wells drilled for 2014 to 26 and the total number of wells drilled into the pool to 106. Production from the pool averaged approximately 9,690 boe/d for the third quarter—6,138 barrels of crude oil and natural gas liquids (NGLs) and 21.3 mmcf/d of natural gas. For the third quarter of 2014, Trilogy’s operating income for the Kaybob Montney oil pool was $52.44/boe compared to $55.53 in the prior quarter. Qua r ter- over- qua r ter produc t ion declined as there were fewer wells drilled in the second quarter to add to thirdquarter production volumes. Three wells drilled into the pool during the third quarter will be completed in the fourth quarter. Three additional wells were expected to be drilled and completed in the fourth quarter and placed on production before the end of 2014 to partly offset production declines in the first quarter of 2015. Production results across the pool have varied depending on Montney net-pay thickness. The early performances of recent wells in the southwestern and northern areas of the pool have been encouraging and will be the focus of further development drilling in 2015. Trilog y ’s capital budget for 2014 provided for eight (7.5 net) horizontal Montney gas wells to be drilled throughout the year. However, with the increase in natural gas prices in the fi rst quarter of 2014, Trilogy accelerated 2013 third- and fourthquarter drilling and completion operations into the fi rst and second quarters, drilling all eight wells during the fi rst and second quarters into the Presley Montney gas pool. This provided Trilogy with the opportunity to drill two (1.5 net) additional wells into this pool during the second half of 2014. These two wells were drilled during the third quarter, with one (0.5 net) well being drilled as an extended reach horizontal well with a lateral length of 3,150 metres in the Montney Formation. OIL & GAS INQUIRER • JANUARY 2015
21
Central Alberta
T h i s we l l w a s e x p e c t e d t o b e completed and on production in the fourth quarter. Tr i log y budgeted $150 m i l l ion f o r D u v e r n a y p r o j e c t s i n 2 014 . A p p r o x i m a t e l y $10 0 m i l l i o n w a s allocated to drilling six net wells on Duvernay acreage that would otherwise expire in 2014, and an additional $50 million was allocated toward nonoperated joint-interest Duvernay drilling and completion operations. During the first quarter of 2014, Trilogy participated in the drilling of two (1.33 net)
horizontal Duvernay wells and the completion of two horizontal wells that were drilled in 2013. Duvernay drilling operations continued through the second quarter with the drilling of eight (5.2 net) horizontal wells, of which four (four net) wells were operated by Trilogy and the remaining four (1.2 net) wells were operated by a third party. No new wells were rig released during the third quarter. However, two (0.8 net) non-operated Duvernay horizontal wells were spudded subsequent to the end of the third quarter in South Kaybob.
Guidance The company also revised its guidance for 2014, boosting its capital expenditures out look to $430 m i l l ion f rom the original guidance of $375 million. Production is now expected to average 35,0 0 0 boe/d compa red to t he previous 36,000. In the current natural gas and crude oil commodity price environment, Trilogy expects to manage its balance sheet through continued production growth, non-core asset rationalization and controlled capital spending.
Talisman reports strong Duvernay results By Richard Macedo
Given recent well results, Talisman Energy president and chief executive officer Hal Kvisle said the company is “excited” about the liquids-rich potential of the Duvernay, and reducing costs in the play will continue to be an area of focus for the producer. In the Duvernay, two Ferrier wells in the company’s southern acreage were completed in the third quarter of 2014, and a Bigstone well in the North Duvernay drilled in the first quarter was completed and brought on stream, the company reported in November. “Talisman holds extensive and very attractive acreage in the South Duvernay, and our two Ferrier tests confirm that we have very liquids-rich acreage in Ferrier,” Kvisle said. The Bigstone well, meanwhile, recorded a 24-hour raw gas test rate of 11.3 mmcf/d of gas and 670 bbls/d of wellsite liquids. This well is now on stream but will be produced at lower rates while the company debottlenecks liquids handling facilities at its Bigstone plant. “We drilled and completed our most recent Duvernay wells with 2,000-metre horizontal laterals with 20-stage fracs of 140 tonnes of sand per stage,” Kvisle said. “We plan to increase frac tonnage substantially in our upcoming completions. We’ve also piloted the ball-drop completion technique on the second Ferrier well, which reduced our completion costs by approximately 30 per cent; we’re now looking into expanding this method to more of our operations in the Duvernay.” 22
JANUARY 2015 • OIL & GAS INQUIRER
Later in 2014, the company was to begin drilling on its liquids-rich Waskahigan and Pine Creek acreage. “We’ll also leverage our infrastructure in Edson to service our northern Duvernay position,” Kvisle said. “The challenge in the Duvernay is cost reduction; we expect to get our cost structure down to $10 [million] to $12 million per well over the long term.
“The challenge in the Duvernay is cost reduction; we expect to get our cost structure down to $10 [million] to $12 million per well over the long term.” — Hal Kvisle, president and chief executive officer, Talisman Energy
We’ve made significant progress already with our best wells running in the $15m i l lion ra nge,” w it h improvements expected to come from larger programs with multi-well pads.
Kvisle laid out a couple of different scenarios in terms of Duvernay development, depending on commodity prices— one would see Talisman aggressively develop 80 per cent of the acreage. “We’d be getting into some of the lesser attractive acreage if we did that,” he said. “If we were running a program of approximately that magnitude, that’s capital north of $1 billion a year and that kind of a program could go on for five to 10 years. “Under the right commodity price environment, for the Tier 1 plus Tier 2 acreage of the Duvernay, you might see us develop something approaching 240,000 acres of that total position, and to make that make sense you’d have to see stronger gas prices because some of that acreage is prolific, but it’s dry gas, or relatively dry gas.” On the other hand, he pointed to areas like Waskahigan, Ferrier, Bigstone and Pine Creek where 80 per cent of the acreage is highly attractive, even at today’s prices. “In that scenario, you might see us spend half as much capital…maybe $400 million a year just to focus on those core areas. If we pursue the first option of aggressive development in the stronger commodity price environment…in that scenario we absolutely need a partner, we need a 50/50 partner. “In the more focused program, in just the very best of our Tier 1 acreage, we are considering whether we might go that on our own in order to maximize value for Talisman.”
Central Alberta
Production climbing at Paramount Paramount Resources’ third-quarter 2014 production was on the upswing as the company reported output of 21,933 boe/d versus 20,008 boe/d for the comparable period in 2013. The company delivered fi rst sales gas from its 200 mmcf/d Musreau deep cut facility in mid-August 2014 and has started the production ramp-up from its inventory of behind-pipe wells. Paramount’s sales volumes reached approximately 40,000 boe/d in early October. Third quarter average sales volumes were approximately 34,000 boe/d, 65 per cent higher than average secondquarter 2014 volumes. Short-term constraints in downstream third-party liquids processing capacity
are temporarily impacting the ramp-up of Kaybob-area production. Production was expected to reach up to 50,000 boe/d by year-end, depending on the availability of sufficient downstream de-ethanization capacity. In 2015, sales volumes are expected to surpass 70,000 boe/d following the completion of additional components of the company’s Kaybob area infrastructure and third-party de-ethanization capacity expansions. Paramount’s total 2014 exploration, development and strategic investments budget has been increased by $100 million to approximately $900 million, excluding land acquisitions and capitalized interest. Prior to the start-up of the Musreau deep cut facility in mid-August, Paramount’s
Paramount gas processing capacity Facility
Musreau Deep Cut Facility Musreau Refrig Plant Smoky Deep Cut Facility Other Musreau area capacity Subtotal
Gross raw capacity Net paramount raw (mmcf/d) capacity (mmcf/d)
Potential sales volumes (boe/d)
,
,
,
,
,
-
-
,
, ,
Capacity under construction Musreau Condensate Stabilizer Expansion 6-18 Plant 3015 Plant
Subtotal
,
Projected total
,
Source: Paramount Resources
production within the Kaybob corporate operating unit was constrained by available owned and contracted natural gas processing capacity. Following the start-up of the new facility, Kaybob-area production began to ramp up, and total company sales volumes increased to approximately 27,000 boe/d in September. Third-party constraints that impacted production at Karr-Gold Creek in the Grande Prairie, Alta., area for most of 2014 were also alleviated in late September with the completion of third-party pipeline expansions. In October, the company continued to ramp up Kaybob-area production, and was also able to flow incremental production at Karr-Gold Creek at Grande Prairie, despite downstream third-party constraints. The ramp-up of Kaybob-area production is being impacted by short-term constraints in downstream third-party de-ethanization and fractionation capacity for other natural gas liquids. Paramount said it is maximizing production through its available deethanization and fractionation capacity, and continues working to source additional interruptible capacity where available. Kaybob’s first 10-well Montney pad was fractured in the third quarter, with aggregate test rates of 108 mmcf/d of natural gas (10.8 mmcf/d per well) plus liquids for the 10 wells. Surface equipment is currently being installed and the wells are scheduled to be brought on stream before the end of the first half of 2015. Paramount said it has fractured and f lowed-back its first t wo horizontal Duvernay wells in the Willesden Green area of Alberta. The fi rst well was scheduled to be brought on production by the end of 2014 and the second well in early 2015.
Gibson Energy is a growth-oriented, solutions-based, North American midstream energy service company with an integrated portfolio of businesses.
w w w. g i b s o n s . co m
OIL & GAS INQUIRER • JANUARY 2015
23
“Industry Leading Quality & Service Since 1987” Specialists in internal & external coating applications Epoxies • Metallizing • Plural Spray Pipe • Tanks • Vessels • Bends • Valves 6150 - 76 Avenue, Edmonton, AB T6B 0A6 Phone (780) 440-2855 Fax (780) 440-1050
• 100% Canadian Owned • www.brotherscoating.com
1964 - 2014
MINING
Stocking Distributor of:
FORESTRY
OIL & GAS
AGRICULTURE
PETROCHEMICAL FOOD PROCESSING WATER & WASTE WATER
Process Control Solutions Since 1964
Stocking Distributor of:
Velocity Flow Metering Products
Level Measurement Solutions
Process Control
Distribution Center
Liquid Level Controls
Magnetic and Coriolis Flow – Meters
Specialized Wellhead Products
9611 - 42nd Avenue, Edmonton, AB T6E 5R2 P: 780.432.6821 F: 780.432.6867
Process Equipment
Measurement Recording
Differential Pressure Flow Measurement Diagnostics
Flow Measurement Accuracy
Electronic Control & Protection
Framing Systems
RCS Actuators
Signalling and Notification
Solar Powered Zero Vent Technology
Digital Display and Control Instrumentation
Specialty Gases & Equipment
Portable Gas Detection
Order Desk & Customer Service 1.877.PEMBINA (736.2462)
www.pem-controls.com Powered by People.Driven by Dedication sales@pem-controls.com
Sales Of f ice
235038 Wrangler Road SE, MD Rockyview, AB T1X 0K3 P: 403.724.3201
SOUTHERN ALBERTA WELL ACTIVITY NOV/13
NOV/14
Wells licensed
85
NOV/13
NOV/14
Wells spudded
89
NOV/13
NOV/14
80
Rigs released Source: Daily Oil Bulletin
▼
▲
▲
S.A.B. Southern Alberta
Production growth helps drive improved DeeThree results DeeThree Exploration posted DeeThree recent Belly River well performance 100 per cent success rate and improved cash flow, earnings and placed all on stream. Well Completion IP IP IP Current number date (2014) (boe/d) (boe/d) (boe/d) (boe/d) revenue as it achieved record proThree rigs currently are in Jan 24 586 517 461 133 duction in the third quarter and operation on the play. nine months of 2014. During the third quarter Feb 2 205 197 183 75 of 2014, DeeThree acquired an C a sh f low i nc r e a s e d to Feb 1 528 383 364 220 additional 12,000 net acres at $52.72 million in the three months Feb 20 1,083 804 693 232 ended Sept. 30, 2014, compared to Brazeau. The company has iden Feb 25 645 444 396 175 $29.41 million in the comparable tified an additional 40 horizontal Feb 22 815 619 523 159 period in 2013, an increase of 77 drilling locations on this acreage Mar 19 403 350 328 284 per cent. For the nine months, bringing the total inventory to cash flow rose to $131.42 million approximately 440 drilling loca Mar 21 1,257 920 701 183 from $68.64 million. tions and its land base to a total of Mar 24 968 801 690 358 Sales averaged 12,294 boe/d, 116,800 net acres. Jun 15 365 279 248 147 82 per cent of which was oil and Wells drilled in 2014 con May 10 950 742 629 294 natural gas liquids (NGLs), up tinue to outperform previous Jun 29 666 524 433 315 62 per cent over 7,573 boe/d in drilled wells. Jul 7 692 634 538 525 the third quarter of 2013, driven Based on these results and in anticipation of further producby strong drilling results. Oil Jul 23 275 227 n/a 93 tion gains, DeeThree continues and NGL production rose 65 per Aug 3 878 886 n/a 1,165 cent to 10,061 bbls/d from 6,088 to expand its 100 per cent owned Aug 6 973 881 n/a 646 bbls/d over the same quarter infrastructure. During the third Aug 30 1,249 n/a n/a 613 of 2013. quarter of 2014, it expanded its Source: DeeThree Exploration oil and gas processing capacity In the third quarter of 2014, Note: Based on production days. per unit operating costs declined at its central pipeline–connected to $9.63/boe, an eight per cent decrease With its ongoing exploration program, battery to 12,000 bbls/d from 8,000 bbls/d. DeeThree drilled a successful seven-mile from $10.46/boe in the same period in 2013. In the Alberta Bakken, production averIn addition to record production, step-out to its existing Alberta Bakken pool, aged 4,879 bbls/d in the third quarter of DeeThree also achieved major milestones significantly expanding its drilling inventory 2014, up 19 per cent quarter-over-quarter in the development of its Brazeau Belly and the pool’s ultimate resource potential. due to continued strong results in its core River and Alberta Bakken properties. Capital spending totalled $85 million in development area. The company drilled Major facility and pipeline projects the third quarter, with $56.5 million spent four horizontal wells throughout the quarwere completed in DeeThree’s Brazeau on drilling and completions, $14.6 million ter, all of which are on stream. Belly River property, significantly increason major facility expansions, $4.4 million DeeThree said it is committed to ing capacity available for future growth. on tie-ins, $8.9 million on minor acquisienhancing oil recoveries and profitability The company also took delivery, installed tions and land, and $600,000 on capitalized on this long-life oil resource. Effective July general and administrative and other assets. 31, 2012, the company’s independent and brought on stream a built-for-purpose gas injection compressor that has expanded Belly R iver production averaged re ser ve eng i neer i ng f i r m, Sprou le its natural gas injection enhanced oil recov6,884 boe/d in the third quarter of 2014. Associates, evaluated the discovered and ery (EOR) project in its Alberta Bakken Throughout the third quarter, the comundiscovered oil resources of the company’s property beyond the pilot phase. pany drilled seven (6.97 net) wells with a Alberta Bakken property. The company OIL & GAS INQUIRER • JANUARY 2015
25
Southern Alberta
The company’s productive Alberta Bakken oil fairway now stretches approximately 30 miles and consists of a contiguous 100 per cent WI land base.
microbial solutions WWW.DPSMICROBIAL.COM
CONTROL & ELIMINATE PARAFFIN, IRON SULPHIDES AND ASPHALTENES IN OILFIELD PRODUCTION AND INJECTION WELLS .
THE ENVIRONMENTALLY FRIENDLY ALTERNATIVE.
Red Deer, AB
403.990.1582
Calgary, AB
403.686.7020 306.486.2110
Frobisher, SK
26
JANUARY 2015 • OIL & GAS INQUIRER
has since delineated most of the resource identified in this evaluation with its ongoing drilling program. With significant long-term upside available by increasing ultimate oil recovery, DeeThree implemented a natural gas injection EOR pilot project over some of the original wells on the property. As a result of the outcome of the pilot project, it has expanded the scope of the EOR project by the addition of two injectors and the installation of high-pressure gas injection pipelines throughout the pool for future injectors. A built-for-purpose high-pressure gas injection compressor designed to re-inject most of the produced gas from the pool was also brought on stream in September. DeeThree is currently waiting for regulatory approval for a fourth gas injector well and has undertaken an independent reservoir study to help optimize the effectiveness of the EOR scheme. The company recently acquired a 100 per cent working interest (WI) in up to 34.5 contiguous sections (22,080 acres) of land located to the west, directly on trend, and between its existing Alberta Bakken production and the previous discovery wells. The land is strategic to DeeThree and its future plans as it was the last remaining block of land available between the company’s original Alberta Bakken discovery well in 2012 and the existing core oil pool that has now been demonstrated to exceed 70 sections. In the third quarter, DeeThree drilled a discovery well on these recently acquired lands, testing a five-metre thick pay section identified in a vertical strat test well. The well was seven miles from the company’s existing Alberta Bakken production. The horizontal well was successfully drilled and 1,400 metres of Bakken pay was successfully fracture stimulated, placing 155 tonnes of sand over 16 stages using an energized water based system. After stimulation, the well was flowed/swabbed for cleanup for approximately nine days with a fi nal average rate of approximately 70 bbls/d of 34 API sweet reservoir oil and 75 mcf/d of natural gas. DeeThree said it is excited by this sweet, light oil discovery, making it successful in its fi rst step in significantly expanding its prospective lands for Bakken oil production. The company expects to modify well lengths, frac size and well placement in future to optimize results from the large oil in place resource. This discovery well is anticipated to substantially increase the resource potential of its Alberta Bakken property, with a number of new drilling locations having been identified, said DeeThree. The company’s productive Alberta Bakken oil fairway now stretches approximately 30 miles and consists of a contiguous 100 per cent WI land base. The near-term development plan will be focused on the lands between the discovery well and the core development area to the east and will benefit from the initial five per cent Crown royalty holiday. DeeThree plans to drill additional wells in the near future on its Alberta Bakken property to rapidly bring these lands into development.
SASKATCHEWAN WELL ACTIVITY NOV/13
NOV/14
Wells licensed
381
NOV/13
NOV/14
Wells spudded
333
NOV/13
NOV/14
362
Rigs released
▼
▼
▲
Source: Daily Oil Bulletin
S.K. Saskatchewan
Drilling results boost Legacy production Legacy Oil + Gas posted strong production results from the Midale, Turner Valley and Spearfi sh in the third quarter of 2014 along with improved cash flow, earnings and revenue. Cash flow for the three months ended Sept. 30, 2014, was up 18 per cent to a record $95.85 million from $81.02 million in the comparable period of 2013, while cash flow for the nine months rose to $254.97 million from $214.79 million the previous period. Average production grew to a record 25,004 boe/d from 19,489 boe/d in the third quarter of 2013, an increase of 28 per cent, due to the production added with the acquisition of Highrock Energy and Corinthian Exploration combined with continued successful drilling, completion and tie-in of wells in southeastern Saskatchewan, Manitoba, Turner Valley and North Dakota. This was off set somewhat by a scheduled third-party workover on the Quirk Creek facility as well as wet weather conditions in Manitoba and southeastern Saskatchewan.
Legacy recently has exceeded its 2014 exit rate guidance of 27,350 boe/d and said it is positioned to be on track to meet its full year production and capital expenditure guidance. In the third quarter of 2014, per unit operating expenses of $14.88/boe were up four per cent from $14.37/boe in the 2013 period. However, Legacy noted that expenses were down five per cent from $15.50/boe in the second quarter of 2014 (and down six per cent since the fi rst quarter) with the downward trend expected to continue in the fourth quarter of 2014. During the third quarter, the company closed the Corinthian acquisition comprised of 2,800 boe/d of production (86 per cent light oil). In the third quarter of 2014, Legacy drilled 59 (51.6 net) oil wells, with a 100 per cent success rate. Activity in the third quarter included the drilling of 15 (14.2 net) Midale horizontal wells in the company’s Pinto and Steelman areas, and 20 (17.7 net) Spearfish horizontal
wells in the company’s Pierson and North Dakota areas. Legacy had an active quarter developing the Midale Formation with the drilling of 15 (14.2 net) wells in the Taylorton, Pinto and Steelman areas. This drilling included successful development, step-out and exploration wells. Production results have continued to exceed the company ’s t y pe cur ve. Overall, the average 30-day initial production rates from the 19 wells with 30 days of production history was 250 boe/d per well. Well costs have been reduced over the course of 2014 by $150,000 per well and additional cost savings are anticipated, said the company. The Steelman waterflood pilot continues to show positive response, as the two wells offsetting the injector have shown a 500 per cent increase in oil production, said Legacy. Additionally, wells outside the initial pilot area have demonstrated increasing oil production. The company has begun water injection in two other Midale waterflood pilot projects at Steelman.
Land sale revenue plummets in Manitoba The Manitoba government at t rac ted $470,201 in bonus bids at its final land sale of the year, and its annual haul of $1.55 million was the lowest total since 2007. The government sold 896 hectares at an average price of $524.78. Prairie Land & Investment Services paid the bonus high bid of $165,000 for a parcel located in the Pierson area. The lease, which included the southwestern quarter of section 29 at 02-28W1, generated an average price of $2,578.13, also the
hectares
Total acreage sold in 2015
land sale high. The fi rm also acquired an adjacent parcel for $130,000 at an average price of $2,031.25. It included the southeastern quarter of section 29 at 02-28W1. For the full year, Manitoba collected $1.55 million in bonus bids on 6,765.26 hectares at an average of $229. This was the lowest annual bonus total since 2007 when the province attracted just $325,852. For 2013, the industry paid $2.03 million for 4,078.97 hectares at an average of $498.90. The next sale will be held on Feb. 11, 2015. OIL & GAS INQUIRER • JANUARY 2015
27
Top operators in 2014 will set the trend in
2015
Cover Feature
By Darrell Stonehouse
T
here are around 360 public oil and gas producers and upward of 150 private producers plying their trade in western Canada. But while that number sounds impressive, a small number of these companies drill most of the wells in the basin. In the first nine months of 2014, the top 15 operators were responsible for 50 per cent of the 7,581 wells completed. Provincial activity is tied even closer to the big players. In Alberta, the top 10 operators drilled around half the wells in the first three quarters. In Saskatchewan, the top five operators in the province drilled almost half the wells, while in B.C. one company, Progress Energy Canada, was responsible for drilling 30 per cent of all wells in the province. These top operators are the bellwether players in the western Canadian industry, and will set the trend for field activity in 2015. Canadian Natural Resources (CNRL) was the top driller in the first nine months of 2014, completing around 825 wells in western Canada, with the vast majority being conventional heavy oil wells. It was also the busiest driller in Alberta, punching around 635 wells. Expect more of the same in 2015, company president Steve Laut said in announcing CNRL’s 2015 capital budget in November. CNRL plans on spending around $1.1 billion in 2015 to
drill 732 net heavy oil wells. It expects heavy oil production to average between 144,000 and 147,000 bbls/d. The company expects to spend around $480 million drilling 49 net light oil wells in 2015 as it continues to advance horizontal well multi-frac technology across its large land base. In 2014, CNRL acquired natural gas producing assets from Devon Energy Canada and Apache Canada, and plans on leveraging those assets to increase production by around 16 per cent to 1,790–1,830 mmcf/d, in 2015. CNRL expects to spend $920 million on its natural gas business in 2015, and will continue its concentrated liquids-rich natural gas drilling program. Some of that money will be spent to further optimize acquired assets with facility consolidations, well reactivations and facility turnarounds. These activities target generating significant free cash flow at average annual strip pricing. North American natural gas operating costs are targeted to decrease to a range of $1.30–$1.40/mcf in 2015. CNRL also plans to undertake a focused program of strategic wells to maintain the strength of its asset base, targeting to drill 69 net natural gas wells in 2015, comparable to the 77 net wells forecasted for 2014. In mid-December Encana announced a 2015 capital program of between $2.7 billion and $2.9 billion, up from
estimated 2014 spending of $2.5 billion to $2.6 billion. About 80 per cent of the 2015 budget will be spent on four plays—the Montney, the Duvernay, the Eagle Ford and the Permian. The company’s 2015 capital budget assumes a price of $70/bbl for WTI crude and a NYMEX gas price of $4/mmBtu. Asked where the company will cut its capital program if WTI averages less than $70/bbl, company president Doug Suttles declined to say. “We’ll adjust our capital as the year progresses,” he replied. In the emerging Duvernay shale play in northwestern Alberta, Encana plans to spend between $250 million and $350 million next year. It will continue to accelerate development in the Simonette area where it expects to run about three to five rigs and drill 15–25 net wells. An additional $800 million is expected to be invested in the play through Encana’s joint venture with Brion Duvernay Gas (formerly named Phoenix Duvernay Gas), representing a gross investment of between $1 billion and $1.2 billion. Encana expects its net liquids production from the Duvernay to grow by about 200 per cent to average 6,000–7,000 bbls/d in 2015. In the Simonette area Encana will be focused on completing two eight-well pads and one nine-well pad and successfully
OIL & GAS INQUIRER • JANUARY 2015
29
Cover Feature
Top Alberta Operators Operator
Top Saskatchewan Operators
Oil
Gas
Dry
SVC
Total
Success
Operator
Oil
Gas
Dry
SVC
Total
Success
Canadian Natural Resources
599
19
5
62
685
99.2%
Crescent Point Energy
331
-
2
4
337
99.4%
Cenovus Energy
216
-
11
94
321
95.2%
Husky Energy
167
-
1
51
219
99.4%
Husky Energy
216
24
7
29
276
97.2%
Teine Energy
183
-
-
-
183
100%
155
-
-
25
180
100%
ConocoPhillips
60
52
1
63
176
99.1%
Northern Blizzard Resources
Devon Canada
108
11
6
46
171
95.2%
Raging River Exploration
133
-
-
-
133
100%
Canadian Natural Resources
102
-
-
4
106
100%
Beaumont Energy
86
-
-
3
89
100%
Whitecap Resources
84
-
-
-
84
100%
Legacy Oil + Gas
74
-
-
3
77
100%
Yanchang International (Canada)
71
-
1
-
72
98.6%
Encana
18
144
1
-
163
99.4%
Suncor
45
1
1
71
118
97.9%
Pengrowth Energy
88
3
-
21
112
100%
Bellatrix Exploration
48
46
-
-
94
100%
Long Run Exploration
91
-
-
-
91
100%
“
In these environments, and we’ve been through several of these over the last 13, 14 years, we’ll see costs come down because of lower day rates.
“
— Scott Saxberg, president and chief executive officer, Crescent Point Energy
30
bringing them on stream, Suttles told analysts. “Completion activities should be fi nished on the ninewell pad by mid-January, and on the fi rst of the eight-well pads about a month later. We then expect to bring on the third eight-well pad by the second quarter,” he said. Suttles said Encana reduced its Duvernay drilling costs by about 40 per cent this year, compared with 2013. In northeastern B.C., the company plans to spend between $250 million and $350 million in the Montney play next year, running two to three rigs and drilling between 20 and 30 net wells. An additional $350 million is expected to be invested through Encana’s Cutbank Ridge Partnership with Mitsubishi Corporation, representing a total gross investment of between $600 million and $700 million. Montney liquids production is expected to grow by five per cent in 2015 to between 19,000 and 20,500 bbls/d. Gas output is expected to range between 580 and 620 mmcf/d. Crescent Point Energy, the second busiest driller in western
JANUARY 2015 • OIL & GAS INQUIRER
Canada by wells completed and the busiest by metres drilled, is hoping lower costs in 2015 will allow it to maintain activity levels. With an uptick in crude oil prices not likely any time soon, Crescent Point Energy’s president and chief executive officer Scott Saxberg said in November that his company will take a more cautious budgetary approach entering 2015 while keeping a keen eye on potential acquisition opportunities. “We are currently in the middle of our budget process. We haven’t finalized anything yet, but given the recent volatility in commodity prices, we expect the 2015 budget will be slightly lower than 2014 but not significantly,” Saxberg said during a third-quarter conference call. “Likely the lower spending will come from reduced spending in facilities and land, and we’re expecting costs will be lower, which will help keep our planned activity levels similar to 2014. “I think a key point that I like to emphasize is that we’re well protected in these kinds of price environments, and we can execute our business plan and thrive at these price levels,” he added.
Saxberg noted there could be some relief on the cost side, especially expenses related to service and supply. “In these environments, and we’ve been through several of these over the last 13, 14 years, we’ll see costs come down because of lower day rates. We’re already talking to our service providers on that, so there’s an expectation, I think into [2015], that we’ll see lower costs,” Saxberg said. “That allows us to maintain a relative balance of activity levels with those drops in day rates.” In light of the current commodity price dynamic, Saxberg said there should also be some land cost reductions that come into play. “We may budget, for instance, $50 million for land. But obviously with lower commodity prices we may not spend $50 million because of the drop in land costs resulting from the drop in commodity prices—that naturally lowers our capital program.” Those things said, Saxberg said the company is being a little more conservative in its planning. “If we assume the strip price today, and then set our budget and commodity prices drop another $20, we don’t
Cover Feature
Top British Columbia Operators Operator Progress Energy Canada
Top Manitoba Operators
Oil
Gas
Dry
SVC
Total
Success
-
132
-
-
132
Operator
Oil
Gas
Dry
SVC
Total
Success
100%
Tundra Oil & Gas Partnership
95
-
1
2
98
99%
44
-
-
1
45
100%
ARC Resources
9
42
-
-
51
100%
EOG Resources Canada
Encana
-
38
-
-
38
100%
Corex Resources
25
-
-
-
25
100%
Royal Dutch Shell
-
35
-
-
35
100%
Legacy Oil + Gas
15
-
-
-
15
100%
Canadian Natural Resources
4
25
-
1
30
100%
Elcano Exploration
14
-
-
-
14
100%
Harvest Operations
13
3
-
-
16
100%
ARC Resources
11
-
-
-
11
100%
-
16
-
-
16
100%
Corval Energy
9
-
-
-
9
100%
8
-
-
-
8
100%
Tourmaline Oil Talisman Energy
-
15
-
-
15
100%
Crescent Point Energy
Crew Energy
1
10
-
-
11
100%
Highmark Exploration
5
-
-
-
5
100%
Murphy Oil Company
-
10
-
-
10
100%
Melita Resources
4
-
1
-
5
80%
want to be in a position where we’re building a significant amount of debt,” he said. “Naturally, we want to carve back our program on a risk basis to see how the year unfolds, and we typically do that in the middle of the year in June, and then we kind of make another call as to whether to add capital or to then even focus more so on our higher return projects.” Northern Blizzard Resources, the fourth busiest driller in Saskatchewan in the first nine months of 2014, isn’t waiting to cut back on its 2015 capital budget. In November, the company announced that because of the oil price decline, its capital spending for 2015 has been cut to $215 million, $45 million less than the previous guidance of $260 million. “In light of the recent decrease in oil prices and our ability to be nimble, we’ve elected to take a conservative approach to our 2015 budget,” John Rooney, chair and chief executive officer, said. Rooney noted that with no clear outlook for oil prices going forward, it only makes sense to practise prudence. “As everyone knows, oil prices have dropped 25 per cent
cent in the past few weeks [of 2014], and it is not clear to us how long, or even if, prices will recover. This price drop puts pressure on industry cash flows and future capital expenditure plans. We are not immune to these facts,” he said. “Our thinking about this is we have to be prepared to operate the company in this lowerprice environment for a sustained period of time. If prices recover, great. If not, then we will take a disciplined approach to capital allocation early and maintain a strong balance sheet.” Progress Energy Canada, the busiest driller in B.C. in 2014, will likely hold that position again in 2015, despite the early December announcement by its parent company Petronas that it is delaying a decision on its planned construction of an LNG terminal on the West Coast indefinitely. Progress spent around $2.5 billion in the field in 2014 proving up natural gas reserves for the planned export facility. During the peak of the winter drilling season, it had 26 rigs operating on its Montney acreage. In early December, Progress Energy Canada president and
chief executive officer Mike Culbert said he expects that trend to continue. “For the near term, we will continue at the planned pace, but if it takes longer than expected [to approve the LNG terminal] we will have to adjust the program,” he said. Montney producer ARC Resources, the second busiest driller in B.C. in the first nine months of 2014, is also cutting back in 2015. In early November, ARC approved an $875 million
Top Horizontal Operators January – September Operator
Alta.
Sask.
B.C.
Man.
Wells rig released
Metres drilled
Crescent Point Energy
21
347
-
10
378
1,097,146
Canadian Natural Resources
160
51
26
4
241
627,448
Encana
80
-
41
-
121
619,446
Cenovus Energy
290
15
-
-
305
614,392
Progress Energy Canada
18
-
130
-
148
538,482
Husky Energy
107
136
1
-
244
531,355
ARC Resources
60
26
53
14
153
529,471
ConocoPhillips Canada
185
-
-
-
185
445,027
Royal Dutch Shell
45
-
54
-
99
393,547
Tourmaline Oil
62
-
29
-
91
379,488
OIL & GAS INQUIRER • JANUARY 2015
31
Cover Feature
Top WCSB Operators Wells Completed January - September Operator
Oil
Gas
Dry
SVC
Total
Success
Canadian Natural Resources
709
44
5
67
825
99.3%
Husky Energy
383
24
8
80
495
98.1%
Crescent Point Energy
361
-
3
4
368
99.2%
Cenovus Energy
225
-
11
98
334
95.3%
Encana
18
182
1
-
201
99.5%
Teine Energy
183
-
-
-
183
100%
Northern Blizzard
155
-
-
25
180
100%
ConocoPhillips Canada
60
53
1
63
177
99.1%
Devon Canada
108
11
6
46
171
95.2%
Progress Energy Canada
31
132
-
-
163
100%
ARC Resources
104
42
2
-
148
98.6%
Raging River Exploration
133
-
-
-
133
100%
Penn West Petroleum
123
2
-
2
127
100%
Whitecap Resources
124
-
-
-
124
100%
Suncor Energy
45
5
1
71
122
98%
capital program directed at high-value oil and liquids-rich gas development and low-cost Montney natural gas assets, targeting production of 120,000–125,000 boe/d—a 10 per cent year-over-year increase. The 2015 budget is a decrease from its 2014 budget of $975 million. Myron Stadnyk, president and chief executive officer, said the company is fortunate to be rich in profitable opportunities, which create a healthy tension between capital discipline and the appropriate pace of growth, while being responsive to the business environment. “Our 2014 capital program established the foundation for certain long-term development projects, and in 2015 we will build on that momentum by continuing to advance long-term projects, and introduce new pilot projects with a particular focus on liquids potential in the Montney,” he said.
Project economics are based on US$80/bbl of oil (WTI) and C$3/GJ of natural gas. ARC is investing about $635 million (70 per cent of its capital program) in high-netback oil and liquids-rich gas development to boost high-value liquids output, expand oil-handling facilities at Tower, and initiate engineering and design for a new facility at Dawson. The company said it is investing approximately $220 million in its low-cost, high-rateof-return Montney gas assets, exploiting its significant gas resource base, increasing gas production and investing in strategic infrastructure at Sunrise. ARC expects to drill 141 (130 net) operated wells, including three service wells, and to participate in 70 (nine net) non-operated wells. The budget calls for 112 gross operated oil wells with significant activity at Ante Creek,
Private Treaty
TARM INC.
www.tarmonline.com
an apex group company
In Service Production Equipment Various Size Tanks, Flare Stacks, Compressor Packages, Line Heaters and More Site Location: Red Deer, Alberta, T4N 7B6, Canada Deadline for Offers: 1st Quarter of 2015 - Viewing By Appointment Only 28 Items Available Including: Building with Office/MCC & Instrument Air/ESD Section, 2000 BBL Fiberglass Tank, 400 BBL Double Wall Tank, Glycol Triplex Pump & Building, Flare Knockout Package, 1mm BTU Line Heater, EI617/FE650D-2 Sour Gas Compressor Package, 1.5mm BTU Line Heater, Tank Containment & Stairway Landing, 500 Gallon Westeel Methanol Tank, Ariel JGJ-2 Throw Compressor with Waukesha Engine, Vertical Separator Package, LA-2190 Line Heater, M1550.213 Line Heater, 210 BBL Tank, 50 BBL Flare Knockout Drum, Mactronic Flare Stacks, L8766.2 Vertical Separator, Molseive Dehy Package, Plus More Items Online...
For more information, photos or to make an offer visit the website.
www.tarmonline.com
Building with Office & ESD Section
2000 BBL Fiberglass Tank
Glycol Triplex Pump & Building
Flare Knockout Package
1mm BTU Line Heater
EI617/FE650D-2 Compressor Package
TARM Inc. Corporate Head Office, 4017 39139 Hwy 2A, Red Deer, Alberta, T4N 7B6, Canada. Tel: (403) 348-0765 Email: info@tarmonline.com
32
JANUARY 2015 • OIL & GAS INQUIRER
Cover Feature
Top 15 Operators Metres drilled January - September Wells rig released
Total metres
Average depth (metres)
Crescent Point Energy
400
1,124,338
2,811
Canadian Natural Resources
828
1,057,095
1,277
Encana
212
713,767
3,367
Husky Energy
521
697,214
1,338
Cenovus Energy
342
644,598
1,885
Progress Energy Canada
148
538,482
3,638
ARC Resources
154
533,459
3,464
ConocoPhillips Canada
196
459,768
2,346
Tourmaline Oil
101
416,023
4,119
Royal Dutch Shell
100
396,882
3,969
Peyto Exploration & Development
88
371,541
4,222
Bellatrix Exploration
98
350,867
3,580
Bonavista Energy
90
340,584
3,784
Penn West Petroleum
133
326,321
2,454
Pengrowth Energy
118
312,706
2,650
Operator
Tower, Pembina and southeastern Saskatchewan/Manitoba. It also plans nine gross operated liquids-rich gas wells primarily at Parkland, Dawson and Pouce Coupe, and 17 gross operated gas wells primarily at Sunrise and Dawson. ARC plans to complete construction on and commission a new 60-mmcf/d gas-processing facility at Sunrise, doubling Sunrise production to approximately 120 mmcf/d exiting 2015, from the current 60 mmcf/d. ARC expects production will be stable through the first quarter of 2015, decline modestly in the second and third quarters due to turnaround and maintenance activities, and increase in the fourth quarter upon commissioning of the new Sunrise gas-processing facility and with the expanded oilhandling facility at Tower. ARC will invest $75 million in strategic infrastructure at
Sunrise and Tower in 2015 to set the stage for future growth in key areas in the Montney region. With expanded facilities in the B.C. Montney region in late 2015, ARC plans to accelerate oil development at Tower in 2015 by drilling 19 wells. It plans to execute a significant drilling program at Sunrise leading up to the on-stream date of a new Sunrise facility. ARC said it plans to execute a meaningful drilling program at Ante Creek, Pembina and southeastern Saskatchewan/ Manitoba to replace declines, keep existing facilities full and capitalize on liquids production. The company expects significant capital spending in the first and third quarters of 2015, with lower spending in the second quarter during breakup and in the fourth quarter of 2015 once new facilities at Sunrise and Tower are completed and commissioned.
REGISTER NOW! Northern Area Western Conference www.calgary2015.nacecalgary.ca This three-day conference from February 24-26, 2015 will focus on corrosion and asset integrity management in the oil and gas industry and includes: • A multi-track program where industry members share about their experiences. • A regulatory forum to encourage discussion between industry and regulators. • A tradeshow area, allowing discussions between vendors and end-users. • A social agenda with countless opportunities for networking. • A student poster session where emerging leaders can present to industry.
Early bird registration discount is available until January 15, 2015
OIL & GAS INQUIRER • JANUARY 2015
33
Feature
The
new gas
giants Homegrown Deep Basin operators moving into the big leagues By Darrell Stonehouse
34
JANUARY 2015 • OIL & GAS INQUIRER
Feature
A
lmost 40 years after Canadian Hunter drilled its discovery well at Elmworth, marking the modern age of exploration in the Deep Basin of westcentral Alberta, the massive stacked gas resource estimated at 400 tcf remains a favoured target of those looking to build homegrown gas giants. Tourmaline Oil & Gas and Peyto Exploration & Development are the latest to succeed in this effort, with both companies set to deliver over 100,000 boe/d of production from the area in 2015. Improvements in horizontal drilling technology and multistage fracturing are driving the current rush of production out of the Deep Basin, with the play one of the few economic opportunities in North America’s saturated natural gas markets. Both companies expect to continue pushing development in the play despite the recent downturn in oil and liquids prices. Tourmaline, with 2,150 gross sections in the Deep Basin, is the largest landholder in the region. Over the last six years, the company has identified more than 3,200 vertical targets and 4,000 horizontal targets on its land base. Current production is around 85,000 boe/d from a reserve base of over 300 million boe. By the end of the third quarter of 2014, Tourmaline had drilled 73 horizontals in the Deep Basin targeting the Wilrich, Notikewin and Falher formations. Company president and chief executive officer Mike Rose says Deep Basin horizontal wells continue to blow away his expectations. “Our horizontal results are primarily in the Wilrich and Notikewin, but we have tested other formations,” he explains. “They continue to significantly outperform our 30-day IP economic template of five mmcf/d. Of the 51 wells we know that have 30 days production history or more, the average 30-day IP is 10.1 mmcf/d.” Tourmaline has been on a tear building processing infrastructure in the Deep Basin as well. Current capacity is 500 mmcf/d, with another 100 mmcf/d on track for the second half of 2015. In 2015, Tourmaline plans on spending $1.4 billion across its three core areas: the Deep Basin, the northeastern B.C. Montney and the Peace River High Charlie Lake oil play. Plans call for a $1.14-billion drilling and completions program employing 16 rigs, with an additional $410 million to be spent on facilities. The company said it would revisit the exploration and production program and the pace of activity during the second quarter of 2015/spring breakup in light of the commodity price outlook at that time. But as it stands, Rose says it’s full steam ahead. “In this volatile price environment, I think it’s important to remember that Tourmaline’s natural gas plays are profitable on a full-cycle basis at prices below $3/mcf and our oil
complex is profitable full-cycle at oil prices below $35/bbl,” he explains. Peyto Exploration and Development is also pushing forward with its big plans in the Deep Basin. Speaking at its third-quarter conference call, Peyto president and chief executive officer Darren Gee said the company’s growth in the Deep Basin over the last five years has been remarkable. “We’ve invested over $2.5 billion and grown production from under 20,000 boe/d to 85,000 boe/d,” he noted. Peyto has achieved this growth with fewer than 50 employees, adding to the accomplishment. “But one of the reasons—the big reason I think—that we can do so much is that we always have a very good game plan, and the risk that we don’t get what we’re planning is actually very low,” he explained. “We’ve always stated that our strategy from day one has been low-risk, repeatable, predictable returns. And when you think about it, when you’re scrambling around, trying to figure out how to deal with some big problem or figure out why things didn’t work out the way that they were supposed to, that takes a lot more people, and it knocks you off your game plan, and it distracts you from your goals. And we rarely have to deal with that. “Now some might say that being so predictable and being so repeatable and low-risk is boring because then we’re not using the latest, greatest technology that they can’t write about, and we’re not chasing the hot new play. But quite frankly, I don’t care. I mean, low-risk, repeatable, predictable—that’s how we’re able to accomplish what we have with this lean and efficient team,” he added. A pure Deep Basin player, Peyto has 701 net sections of land and currently produces around 85,000 boe/d. Much of its growth has come from development of the Wilrich, Notikewin and Falher zones, but the company has recently added a focus on the Bluesky Formation. Peyto currently has over 1,700 remaining drilling locations identified in the Deep Basin, with 1,000 wells currently in operation. Like Tourmaline, Peyto controls almost all its processing through its nine owned and operated gas plants. In early November, the company announced a preliminary 2015 budget of $700 million to $750 million, the sixth year in a row that the capital budget has increased compared to the previous year. The 2015 program involves drilling between 124 and 137 gross wells (117 and 130 net to Peyto’s working interest) utilizing nine to 10 drilling rigs with only minimal interruption expected during the traditional spring breakup. The 2015 drilling locations are expected to add between 41,000 and 45,000 boe/d of new working interest production, for a cost of approximately $17,000/boe/d.
OIL & GAS INQUIRER • JANUARY 2015
35
Feature
Peyto Exploration Deep Basin well performance by producing zone
Tourmaline Deep Basin economics
Cardium
Notikewin
Upper Falher
Middle Falher
Wilrich
Bluesky
Brazeau Falher
Brazeau Wilrich
Well costs (D&C, $ millions)
3.5
4.3
4.1
4.2
4.3
4.2
4.6
4.8
Reserves (bcfe)
2.2
3
3.4
2.9
3.3
3.2
3.5
3.3
IP30 (mcf/d)
1,500
4,000
5,000
3,500
3,500
3,500
5,000
3,500
Gas/liquids ratio (bbls/mmcf)
40
10
23
13
5
13
10
5
Payout (years)
2.3
2
1.3
2.6
2.7
1.6
1.9
3.1
IRR full cycle (%)
22
28
48
22
23
43
32
20
Source: Peyto Exploration November presentation
While this level of capital efficiency is consistent with the past several years, more recently production has been added at $16,330/boe/d, according to the company. A portion of this new production addition will offset an internally forecast 35 per cent base decline, while a portion will grow overall 2015 production from an expected 2014 exit level of 85,000 boe/d to a forecast 2015 exit level between 96,000 boe/d and 100,000 boe/d. Approximately 40 mmcf/d of additional processing capacity will be added to Peyto’s Swanson and Brazeau gas plants, while approximately 20 mmcf/d will be added to Peyto’s Oldman North and Wildhay gas plants in order to accommodate the 2015 production growth. These facility investments, which represent 17 per cent of the capital budget, have already been ordered to ensure that timely installation coincides with drilling results. By the end of 2015, Peyto expects to own and operate approximately 750 mmcf/d of processing capacity in the Alberta Deep Basin. Peyto said Alberta natural gas prices are currently forecast to average approximately $3.76/GJ in 2015, almost identical to the $3.73-average price of Peyto’s hedges for the year (which volume represents approximately 40 per cent of forecast production). These prices, when adjusted for Peyto’s historic natural gas liquids and heat content premiums of 135 per cent and combined with the company’s cash costs of approximately $1/mcf ($6/boe), should yield cash netbacks of approximately $23–$24/boe. At the company’s third-quarter conference call in November 2014, Peyto executives said they expect Deep Basin costs to remain constant in 2015. “Earlier when the oil price was stronger, we were hearing hints of potential small increases coming into the winter here, and some of our service providers have backed off on that, suggesting that we shouldn’t see those costs as they might have at one time anticipated,” Gee said. “Looking at it at this point in time, we’re assuming that our cost structure will more or less be consistent through the winter where it has been here in the last few weeks.” Peyto also continues working to improve drilling and completion efficiencies in the Deep Basin. The company reported
36
JANUARY 2015 • OIL & GAS INQUIRER
Outer Deep Basin Foothills Vertical Vertical Total well costs ($ millions)
Deep Basin Horizontal
4
5.25
5.8
2.5
6
5.5
1.45
3
3.5
Development cost/boe
$9.60
$5.73
$6.33
Operating expense/boe
$4.00
$4.50
$3.50
8
9
9
Average reserves/well (bcfe) Year 1 production rate (mmcf/d)
Royalty rate (%)
that it now takes Internal rate 35 73 76 nine rigs to do the of return (%) amount of work it $4.30 $4.40 $4.35 Year 1 gas price took 10 rigs to do Future in 2013. 2,750 450 4,000 development Improvements locations in operational *Development locations based Source: Tourmaline on two wells per section. execution, combined with longer horizontal well laterals, have resulted in a 10 per cent average productivity improvement over previous years. As this was accomplished for the same capital cost, the trailing 12-month capital efficiency has improved to $16,330/boe/d. “It’s important to point out that, despite the fact we’re drilling consistently longer horizontals year-over-year, we’re also getting them done cheaper,” said Jean-Paul H. Lachance, Peyto’s vice-president of exploitation. “The typical 4,000-metre well back in 2011 drilled today now costs us $400,000 less. This is more impressive when you consider that [2014’s] drilling program includes some more costlier wells down in our Brazeau area. So if we look at our Sundance area in isolation, where we still have a vast inventory of Spirit River locations, average drill costs are down under $2.5 million with individual well costs routinely coming in, in the $2.2 million to $2.4 million range. But that’s not to say that we’ve not moved up the learning curve in Brazeau. We now have shown that we can drill wells there for under $3 million, which is a vast improvement over the earlier wells. “On the completion side, costs are relatively flat over the last two years, which is good, considering we’re fracking more stages with the longer horizontals and the increase in density on some of our wells,” he added. The company is also looking to add to its land base in the play. Tim Louie, vice-president of land, noted the bonus paid and the amount of land disposed in 2014’s sales lag behind values from the previous year.
“we’Ve TesTeD OUR TYPe CURVes Using FULL-CYCLe COsTs againsT VaRiOUs PRiCes, anD we FeeL COnFiDenT anD COMFORTaBLe ThaT MOsT OF OUR weLLs PLanneD FOR neXT YeaR MaKe Us a POsiTiVe ReTURn, eVen aT $3 gas PRiCes.”
Feature
®
— Jean-Paul H. Lachance, vice-president of exploitation, Peyto
Manufacturer of: • Water storage tanks up to 12,000 imp. gal. • Water hauling tanks • Chemical tanks • Secondary containment basins • 300, 500 & 1,000 gallon double wall tanks 12015 152 Street NW, Edmonton, AB T5V 1G4 Phone: 1.888.474.7441 | Fax: 780.474.3454 Fax: info@norwescocanada.com
Fleet Reporting
We’ve got the right vehicle for your next oilfield project.
Fleet Management
Leasing
www.norwescocanada.com
*All makes & models
Remarketing
“However, the trend of higher average prices has continued on,” he said. “Although we are seeing increased competition in the form of higher per-acre bids, we have been successful in acquiring 34 sections within our focus areas. “With regards to companies with expiring lands, we haven’t seen a noticeable change in behaviour. Unfortunately, there are a lot of companies that are not motivated to sell or farmout expiring acreage. Although we tried to negotiate deals on prospective expiring acreage, we typically have to wait for these lands to expire and then post the lands for a future sale.” Louie said some companies are prepared to capture value from their expiring lands. “Early in [2014], we acquired six sections in the Brazeau area; we negotiated a modest purchase price since the lands were due to expire in nine months,” he noted. Gee said he sees the current downturn in the industry as an opportunity for growth. “There’s times, arguably, when we want to be more aggressive investing shareholder capital because we know that those are the best times to be generating the maximum amount of return,” he explained. “And typically, those are when we’re in an off-cycle, which affects the commodity prices, industry activity is down, costs are down, so sort of countercyclical to the rest of the industry. And in those times, we want to be as aggressive as we can, so we use cash flow, debt, equity, all funding sources to put the maximum amount of capital to work at those times because we know that’s when we can generate the best returns. “And then there’s other times when costs are high and activity is really high, and those are typically the wrong times for us to be investing capital when we’re really challenged to make those same returns,” he added. “And so we pull back capital programs.” “We’ve tested our type curves using full-cycle costs against various prices, and we feel confident and comfortable that most of our wells planned for next year make us a positive return, even at $3 gas prices,” added Lachance. “It may seem like an ambitious plan for 2015, but the Peyto team has already proven [in 2014] we can successfully deploy a $700-million program. So we look forward to spending even more into the business environment, and the results are warranted.”
www.jimpattison lease.com
OIL & GAS INQUIRER • JANUARY 2015
37
advertisers' index Annugas Compression Consulting Ltd . . . . . . . . 20
DPS Microbial Solutions . . . . . . . . . . . . . . . . . . . 26
Pembina Controls Inc. . . . . . . . . . . . . . . . . . . . . . 24
Ar-Tech Coating Ltd . . . . . . . . . . . . . . . . . . . . . . . 10
Dragon Products Ltd . . . . . . . . . .inside front cover
Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
BC Research. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
DSI Thru-Tubing Inc . . . . . . . . . . . . . . . . . . . . . . . . 6
Phoenix Fence . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Gibson Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Scott Builders Inc. . . . . . . . . . . . . . . . . . . . . . . . . 16
Blue Spark Energy . . . . . . . . . . .outside back cover
Hemmera . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
TARM Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Brother’s Specialized Coating Systems Ltd . . . . 24
Jim Pattison Lease . . . . . . . . . . . . . . . . . . . . . . . . 37
Tartan Canada Corporation . . . . . . . . . . . . . . . . . 19
Canoils . . . . . . . . . . . . . . . . . . . . . inside back cover
Mainland Machinery Ltd . . . . . . . . . . . . . . . . . . . 26
Tier 1 Energy Solutions Inc. . . . . . . . . . . . . . . . . . . 8
CG Industrial Specialties Ltd . . . . . . . . . . . . . . . . . 4
Meridian Manufacturing . . . . . . . . . . . . . . . . . . . 14
V J Pamensky Canada Inc. . . . . . . . . . . . . . . . . . . 12
Chase Operator Training . . . . . . . . . . . . . . . . . . . 18
NACE Northern Area Western Conference. . . . . 33
Vortex Drilling Ltd . . . . . . . . . . . . . . . . . . . . . . . . 24
Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 37
Weyburn Oil Show Board . . . . . . . . . . . . . . . . . . . 15
38
JANUARY 2015 • OIL & GAS INQUIRER
THE MOST ACCUR ATE FINANCIAL AND OPER ATING DATA AVAILABLE ON THE CANADIAN OIL AND GAS INDUSTRY
KNOCK. KNOCK. COMPREHENSIVE DATA ENSURES YOU NEVER MISS AN INVESTMENT OPPORTUNITY.
CanOils gives you detailed coverage on TSX and TSX-V listed oil and gas companies, including hard-to-find E&P reserves, production and cost information. Organized, accurate and structured data allows you to quickly analyze and integrate with Excel and your existing in-house systems.
CanOils also offers: Complete oilsands project information Historic financial/operating data and presentations
WE OPEN THE DOOR FOR YOU TO IDENTIFY AND EXPLOIT OPPORTUNITIES.
NEED DATA THAT WILL INFOR M YOUR DECISIONS?
www.canoils.com 403.269.6003 CANOILS IS PART OF THE GLOBAL OIL AND GAS DATA SPECIALIST, EVALUATE ENERGY.
Broker forecasted performance data Daily coverage of all Canadian M&A deals