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CONTENTS
DECEMBER.13
in the news
9
AER still learning about shale resources
regional news
15
British Columbia
Timing critical for Canada’s LNG projects
19
Northwestern Alberta
27
Central Alberta
Williams Energy propane project could be just the beginning of petrochemical growth
Shell moving forward with Carmon
31
Creek project in Alberta
Twin Butte to acquire Black Shire
23
Northeastern Alberta
Southern Alberta
Merry Christmas from all the staff at
for $358 million
Suncor sanctions $13.5-billion
35
Fort Hills oilsands mine
Raging River bulks up in Dodsland Viking
Saskatchewan SMART DEADWEIGHT AND PRESSURE HOUND PRODUCTS PORTABLE CUSTOM DATA ACQUISITION SYSTEMS
features
PRESSURE AND FLOW CALIBRATION TRACEABLE TO NATIONAL STANDARDS
Cover Feature
INSTRUMENT RENTALS SYSTECH HAS RELOCATED TO THE FOLLOWING ADDRESS TO BETTER SERVE OUR CUSTOMERS
38 44 47 50 Slow burn Natural gas prices flickered back to life in 2013, but could flame out without new demand
Tight rope Volatility is the word for Canadian oil prices in 2014 and beyond
Rat race Energy service companies overshoot demand, waiting for LNG exports before major new growth begins
Network interrupted Political logjam stalled needed oil pipelines in 2013, but 2014 could mark the start of a construction boom
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business intelligence
53
Structured joint ventures offer an alternative to equity markets
every issue
6 54
Stats at a Glance Political Cartoon Cover design: Peter Markiw
OIL & GAS INQUIRER • DECEMBER 2013
3
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Editor’s Note Vol. 25 No. 10 EDITORIAL EDITOR
Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS
Lynda Harrison, Carter Haydu, Richard Macedo, Pat Roche, Elsie Ross, Paul Wells
Institutional amnesia
EDITORIAL ASSISTANCE MANAGER
Tracey Comeau | tcomeau@junewarren-nickles.com EDITORIAL ASSISTANCE
Kate Austin, Shawna Blumenschein, Matthew Stepanic CREATIVE
Governments across North America have forgot-
per barrel in early 2013. The differential between
ten how to move pipeline projects through their
Western Canadian Select heavy crude and WTI
Tamara Polloway-Webb | tpwebb@junewarren-nickles.com
self-created regulatory quagmire, costing both
has averaged almost $23 per barrel in the first
CREATIVE LEAD
the industry and themselves tens of billions of
nine months of 2013. The Alberta government
dollars in lost revenues.
estimates this double discount is costing the
PRINT, PREPRESS & PRODUCTION MANAGER
Michael Gaffney | mgaffney@junewarren-nickles.com CREATIVE SERVICES MANAGER
Cathlene Ozubko GRAPHIC DESIGNER
Peter Markiw
CREATIVE SERVICES
“Why can’t we get this infrastructure built?
Canadian economy about $27 billion per year, or around $75 million per day.
Janelle Johnson, Jeremy Seeman production@junewarren-nickles.com
It’s not rocket science. We’ve been building it for
SALES
aground on building new infrastructure,” Russ
charge of approving interprovincial pipelines like
Monte Sumner | msumner@junewarren-nickles.com
Girling, president and chief executive officer of
the Northern Gateway. The fact it has taken six
SENIOR ACCOUNT EXECUTIVES
TransCanada Corporation, told the Economic
years to launch a review for this pipeline should
Club of Canada Inc.’s Canadian Energy Summit
be a major scandal.
SALES MANAGER—ADVERTISING
Nick Drinkwater, Tony Poblete, Diana Signorile SALES
the past 100 years, and all of a sudden we’ve run
Terry Nelson Browning, Brian Friesen, Rhonda Helmeczi, Sammy Isawode, Mike Ivanik, Nicole Kiefuik, David Ng, James Pearce, Sheri Starko
2013 in early November.
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governments have been dithering on approval of
AD TRAFFIC COORDINATOR—MAGAZINES
Lorraine Ostapovich | atc@junewarren-nickles.com DIRECTORS
Here are some numbers that lay out how badly new pipelines, and the cost of that dithering. Enbridge Inc.’s Northern Gateway Pipeline,
The federal government in Canada is in
In fact, the government should also be expediting the Trans Mountain expansion and the Energy East Pipeline. After all, pipelines are not a new technology. The first Canadian line to move natural gas
designed to move 525,000 barrels of oil from
was built in 1853. Oil has been piped in Canada
Bill Whitelaw | bwhitelaw@junewarren-nickles.com
Alberta to the West Coast, was formally launched
since 1862. With over 100,000 kilometres of
PRESIDENT
in 2004. In 2006, Environment Canada called
pipeline across the country, the technology is
for a joint review panel on the line. That review
well understood.
CEO
Rob Pentney | rpentney@junewarren-nickles.com DIRECTOR OF SALES & MARKETING
Maurya Sokolon | msokolon@junewarren-nickles.com
panel didn’t begin to hear public testimony on the
DIRECTOR OF EVENTS & CONFERENCES
proposed pipeline until 2012. Six years. A deci-
construction of the new lines. Eighty per cent
sion on the project is expected in 2014, 10 years
want to see oilsands crude sent to eastern
after the pipeline was proposed.
Canada, according to a recent Ipsos Reid
Ian MacGillivray | imacgillivray@junewarren-nickles.com DIRECTOR OF THE DAILY OIL BULLETIN
Stephen Marsters | smarsters@junewarren-nickles.com DIRECTOR OF DIGITAL STRATEGIES
Gord Lindenberg | glindenberg@junewarren-nickles.com DIRECTOR OF CONTENT
Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION
TransCanada’s Keystone XL Pipeline,
Also, the Canadian public supports the
survey. Two-thirds of Canadians are in favour
designed to carry 830,000 barrels of oil per day
of pipelines to the West Coast to serve interna-
from Alberta to refineries on the U.S. Gulf Coast,
tional shipping ports. Yet the federal government dithers. It can’t
Audrey Sprinkle | asprinkle@junewarren-nickles.com
was announced in 2008. Almost six years later,
DIRECTOR OF FINANCE
no decision has been made on the line in the
control what the United States does with the
United States.
Keystone XL line, but its actions on the domestic
Ken Zacharias, CMA | kzacharias@junewarren-nickles.com OFFICES Calgary
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SUBSCRIPTIONS Subscription Rate
The cost of these delays is staggering. With
pipelines are inexcusable.
no way to get oil to offshore markets and rising
Something needs to be done.
North American production, many Canadian
That’s this month’s rant.
producers have been facing a double discount. West Texas Intermediate (WTI) prices have
Darrell Stonehouse
traded at a discount to world prices as high as $20
Editor dstonehouse@junewarren-nickles.com
In Canada, 1 year $49 plus GST, 2 years $69 plus GST Outside Canada, 1 year $99
Subscription Inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren-nickles.com GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2013 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.
N E XT I S S U E January 2014 A look at advances in drilling technology, plus a review of Deep Basin development activity.
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 • DECEMBER 2013
5
FAST NUMBERS
$.
US$
per thousand cubic feet
per barrel West Texas Intermediate
PSAC 2014 AECO gas price forecast.
PSAC 2014 oil price forecast.
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
OIL
GAS
T O TA L
MONTH
OIL
GAS
D RY
SERVICE
T O TA L
Oct
Oct
,
,
Nov
Nov
,
Dec
Dec
,
Jan
Jan
Feb
Feb
,
Mar
Mar
,
Apr
Apr
Jun
Jun
Jul
Jul
Aug
Aug
Sep
Sep
Oct
Oct
,
Wells Drilled in British Columbia
Saskatchewan Completions
Source: B.C. Oil and Gas Commission
Source: Daily Oil Bulletin
MONTH
WELLS DRILLED
C U M U L AT I V E *
MONTH
OIL
GAS
OTHER
TOTAL
Oct
Oct
Nov
Nov
Dec
Dec
Jan
Feb
Jan
Mar
Feb
Apr
Mar
Jun
Apr
Jul
Jun
Aug
Jul
Sep
Oct
*From year-to-date
6
OTHER
DECEMBER 2013 • OIL & GAS INQUIRER
Aug
Sep
Oct
STATS
AT A
GLANCE
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, November 11, 2013 Source: Rig Locator
Alberta, November 2013 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada Alberta British Columbia
Manitoba Saskatchewan WC TOTALS
AC T I V E
OIL WELLS
Alberta
Nov
GAS WELLS
Nov
Nov
%
Northwestern Alberta
%
Northeastern Alberta
%
Central Alberta
59%
Southern Alberta
%
TOTAL
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada, November 11, 2013 Source: Rig Locator
Alberta, November 2013 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
AC T I V E (Per cent of total)
Western Canada
Alberta
Nov
C OA L B E D M E T H A N E
Alberta
Nov
Nov
BITUMEN WELLS Nov
Nov
%
Northwestern Alberta
British Columbia
%
Northeastern Alberta
Manitoba
%
Central Alberta
Saskatchewan
%
Southern Alberta
WC TOTALS
%
TOTAL
OIL & GAS INQUIRER • DECEMBER 2013
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IN THE
NEWS Issues affecting Canada’s E&P industry
shale
AER still learning about shale resources By Carter Haydu
While the study published by the Energy Resources Conser vation Board, now the Alberta Energy Regulator (AER), of unconventional shale/siltstone resources reported massive estimates of resource in place, researchers were largely more interested in what they were able to learn about the rocks themselves. “One of the things we did right in the beginning is we said, ‘Let us pretend these rocks are moon rocks,’ and that’s exactly what we did,” Dean Rokosh, section leader of energy resource appraisal for the geology and environmental sciences branch at AER, told an unconventional resources conference in October. “We said: ‘It’s a moon rock; we know nothing about this rock, so let us start from
A and do every test we can do to figure out everything we can about these formations,’” he said. “When we look at the data entirely, I think the biggest issue we had is still that accuracy question: how close to accuracy is our data?” The study, A Summary of Alberta’s Shale- and Siltstone-Hosted Hydrocarbon Resource Potential, was released last year. It estimates a total resource in place of 3,424 trillion cubic feet of natural gas, 58.6 billion barrels of natural gas liquids (NGLs) and 423.6 billion barrels of oil in shale and/or siltstone formations in Alberta. Based on those calculations, the Duvernay has an estimated 443 trillion cubic feet of natural gas, 11.3 billion barrels of NGLs and 61.7 billion barrels of
Summary of estimates of Alberta shale- and siltstone-hosted hydrocarbon resource endowment Unit Duvernay P Duvernay P–P Muskwa P Muskwa P–P Montney P Montney P–P Basal Banff/Exshaw P (preliminary data) Basal Banff/Exshaw P-P North Nordegg P (preliminary data) North Nordegg P–P
Adsorbed gas content %*
Natural gas (tcf)
Natural gas liquids (billion bbl)
Oil (billion bbl)
.
.
.
.–.
–
.–.
.–.
.
.
.
.–.
–
.–.
.–.
.
.
.
.–.
–
.–.
.–.
.
.
.
.–.
–
.–.
.–.
.
.
.
.–.
–
.–.
.–.
Wilrich P (preliminary data)
.
.
.
Wilrich P–P
.–.
–
.–.
.–.
N/A
.
.
Total P (medium estimate) resource endowment
* The percentage of adsorbed gas represents the portion of natural gas that is stored as adsorbed gas. Source: Alberta Energy Regulator
oil. Rokosh described it as a world-class resource with very high numbers, and he expects those numbers to increase as researchers learn more about it. “I do want to stress that we tried to be reasonable in everything we did. We didn’t want anything to be hype here.” The Muskwa has an estimated 419 trillion cubic feet of gas, 14.8 billion barrels of NGLs and 115.1 billion barrels of oil. Rokosh said that, in his opinion, this formation rock is particularly fascinating. “One of the interesting things about this rock is the fissility. It’s really, really fissile rock, and in areas you can just pick up the core and break it with your hand. What does that mean to fracturing? Well, that’s your business and what you’ll tell us,” he told delegates at the Canadian Society for Unconventional Resources conference. Resource-in-place estimates for the Montney indicate 2,133 trillion feet of gas, 28.9 billion barrrels of NGLs and 136.3 billion barrels of oil, while the Basal Banff/ Exshaw has an estimated 35 trillion cubic feet of gas, 92 million barrels of NGLs and 24.8 billion barrels of oil. To a large degree, the Exshaw is listed as preliminary because of the middle unit, which has highly variable lithology, said Rokosh, who added: “If anything, we’ll have to go back to this and try to establish the relationship between those various lithologies and porosity.” The Nordegg has an estimated 148 trillion cubic feet of gas, 1.4 billion barrels of NGLs and 37.8 billion barrels of oil resources in place, while the Wilrich has 246 trillion cubic feet of gas, 2.1 billion barrels of NGLs and 47.9 billion barrels of oil. “This is not an end—this is a beginning for us,” Rokosh said of the report, stressing that researchers were extremely conservative when making estimation of the formations’ shale resource. “Those numbers will get bigger and probably be substantially larger.”
Me plignias iur, occusandis voluptaquo omnimo voluptium explaudaes con et.
OIL & GAS INQUIRER • DECEMBER 2013
9
fractionation
In The News
Liquids-rich gas driving demand for more fractionation capacity By Elsie Ross
As the boom in liquids-rich natural gas production strains existing fractionation capacity in Alberta, midstreamers are beginning to step up to the plate with new projects either under construction or in the planning stages. “Certainly it has overwhelmed the facilities and infrastructure that were in place to deal with the capture basin [dry gas] that existed,” said Bob Lock, vicepresident of midstream and natural gas liquids at Pembina Pipeline Corporation. “Collectively as an industry, there is an opportunity to build more infrastructure.” The next challenge is whether the market can absorb that volume of product so the price netbacks are still positive for the producer, he said. “That is probably the challenge we are seeing now in the province of Alberta where the propane supply has exceeded the propane market, so now we have to go far afield to look for opportunities to sell these products for the whole value chain.” Lock, though, is “pretty confident” about the continuing demand for fractionation
capacity in Alberta. “I would characterize it as supply push because there is a lot of supply, but the market demand for infrastructure to handle that supply is [in for] pretty exciting times for sure.” Fractionation is the process of taking a mix of hydrocarbons and separating them into their constituent spec products— ethane (C 2), propane (C 3), butane (C 4) and pentane—to obtain full value for the natural gas liquid (NGL) components. The province’s petrochemical plants provide the major market for C2 and increasingly C3, according to the Energy Resources Conservation Board’s—now the Alberta Energy Regulator (AER’s)—Alberta’s Energy Reserves 2012 and Supply/Demand Outlook 2013–2022. C 4 is used as refinery feedstock, blended with light/medium crude oil to benefit from the higher price of crude oil, and used to reduce bitumen viscosity. The largest demand for pentanes-plus or condensate (C5+) is as diluent in the blending of heavy oil and bitumen, and at times
has sold in Edmonton at a premium to West Texas Intermediate. Straddle plants, usually located on main gas transmission pipelines at border delivery points such as Empress, Alta., and Cochrane, Alta., remove much of the ethane and propane-plus (C 3+) volumes. Generally, the heavier NGLs (C 4 and C 5+)
“Large-scale fractionators are connected to the rail and pipeline infrastructure that have the capacity to take large volumes to a larger market.” — Bob Lock, vice-president, midstream and natural gas liquids, Pembina Pipeline Corporation
are removed at field plants, which may send the recovered NGL mix to the centralized, large-scale fractionation plants. Most of Alberta’s fractionation capacity is provided by large-scale plants in the
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DECEMBER 2013 • OIL & GAS INQUIRER
www.MeridianMFG.com
In The News
Alberta’s NGL processing flow
Battery
Alberta border
Alberta gas and NGL market
R Other Canadian markets
Gas pools
Field plants
Raw gas
R
R R
Marketable
U.S. markets
Straddle plants - NGL mix - Ethane - Propane - Butanes - Pentanes-plus
gas
Sulphur
Alliance high-pressure pipeline
Fractionation plants - Ethane - Propane - Butanes - Pentanes-plus
NGL mix - Ethane - Propane - Butanes - Pentanes-plus
Chicago, Ill., extraction plant - Ethane - Propane - Butanes - Pentanes-plus
Schematic of Alberta NGL flow Dry gas
Dry or rich gas NGL mix
Propane/butanes
Specification product Rich gas Oil pools
R Crude oil
Refineries
Point royalties collected
Source: Alberta Energy Regulator
Redwater/Fort Saskatchewan area northeast of Edmonton. In 2012, Pembina’s fractionator at Redwater and the Keyera Corp., Plains Midstream Canada and The Dow Chemical Company facilities at Fort Saskatchewan accounted for 200,000 barrels per day of ethane-plus (C2+) and C3+ capacity. At Redwater, Pembina has one fractionator expansion under construction and is contemplating a second for the C 2+ fractionator it acquired with the acquisition of Provident Energy Ltd. in 2012. The facility, originally developed by TransCanada Midstream, handles both C 2+ and C 3+ mixes delivered via Pembina’s Peace, Brazeau and Northern NGL pipelines. A recent debottleneck ing project increased the capacity of the base facility, RFS I, to 73,000 barrels per day and it is currently being doubled to 146,000 barrels per day at a cost of $415 million. The anticipated on-stream date is the fourth quarter of 2015. In anticipation of a third phase for the fractionator, RFS III, Pembina is taking the opportunity while constructing RFS II to cost-effectively expand site infrastructure to accommodate a further expansion, said Lock. “We are working hard on Redwater III,”
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he said. “There certainly seems to be strong market demand to continue, but it is still in the developmental stages.” Should the third phase proceed, the facility would further leverage engineering and design work completed for the first two phases, according to Lock. Although the scale of the next expansion will depend on the demand from producers, “certainly we would be looking at something large scale again,” he said. “The only thing we are not sure about is whether it will have ethane recovery.” If there is no market for C2 , Pembina will probably build a C3+ fractionator. “But it is still early days, so we could go either way.” At Fort Saskatchewan, Keyera is adding a 30,000-barrel-per-day de-ethanizer that will enable the company to process a C 2 -rich stream of NGLs (C 2+ mix), creating specification C 2 for delivery to petrochemical producers in Alberta and a C3-rich stream of NGLs for delivery into Keyera’s fractionation facilities. The gross cost of the project, which is expected to be on stream in 2014, is $110 million, including pipeline connections and the conversion of a salt cavern to C2+ raw feed storage. It is underpinned by a long-term, fee-for-service agreement with a large producer in the Deep Basin of westcentral Alberta. In addition, Keyera is working on frontend engineering and design (FEED) for a proposed 35,000-barrel-per-day expansion of its existing 30,200-barrel-per-day (23,250-barrel-per-day net) C 3+ fractionation facility at Fort Saskatchewan. Final project approval is expected in the fourth quarter of this year, subject to completion of the FEED study and sufficient producer commitments. Also at Fort Saskatchewan, Plains Midstream Canada is considering a C 3+ fractionation expansion, increasing working capacity to about 66,000 barrels per day, a speaker from Keyera told an NGL markets conference in Calgary in August. In addition to the Fort Saskatchewan– area fractionators, there are eight field fractionators in the province, according to the report. However, the larger fractionators provide economies of scale, says Lock. “If you were to do a small one in the field, you would have to be married to a truck market that has to be awfully close,” he says. “Large-scale fractionators are connected to the rail and pipeline infrastructure that have the capacity to take large volumes to a larger market.”
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BRITISH COLUMBIA WELL ACTIVITY OCT/12
OCT/13
Wells licensed
127
OCT/12
OCT/13
Wells spudded
54
OCT/12
OCT/13
54
Rigs released
▲
▲
B.C. British Columbia
▲
Source: Daily Oil Bulletin
Timing critical for Canada’s LNG projects By Richard Macedo
Timing is critical for Canada’s planned liquefied natural gas (LNG) export projects in British Columbia as they are embroiled in an intense competition with other countries to supply the lucrative Asian market, according to a proponent of the planned Kitimat LNG project. Competitors cited include Australia, the United States and Russia, as well as some African nations. During the 2013 Calgar y Energ y Roundtable conference, Jeff Lehrmann, president of Chevron Canada Limited, said projects like these have “a limited shelf life,” and pointed to the regulatory delays of the Mackenzie Gas Project, which essentially iced that planned pipeline.
Chevron is the operator of Kitimat LNG. Its 50 per cent partner in the planned project is Apache Corporation. “Time is even more critical today because of the intense competition for the LNG market,” he said. “Projects in Canada have to compete for investment dollars against other assets we have in Kazakhstan, Thailand, Australia, China and so on.” Bringing a project like Kitimat LNG to full development will cost tens of billions of dollars, he noted. “Count r ies around t he world are striv ing to capitalize on the natural gas revolution from export opportunities,” he said. “The LNG export market is becoming increasingly competitive,
Proposed B.C. LNG projects 1.
Triton LNG LP: Idemitsu Kosan Co. Ltd. and AltaGas Ltd. each own a 50 per cent interest in the partnership.
2. LNG Canada: LNG Canada is a joint venture comprised of Shell Canada Limited, Korea Gas Corporation, Mitsubishi Corporation and PetroChina Company Limited. The export facility is expected to have an export capacity of 2 billion to 3 billion cubic feet per day . 3. Kitimat LNG: Apache Canada Ltd. and Chevron Canada Limited each own 50 per cent of the Kitimat LNG project. The facility is expected to have an export capacity of 0.75 billion to 1.50 billion cubic feet. 4. Pacifi c NorthWest LNG: Progress Energy Canada Ltd. and PETRONAS sponsor this project. The facility is expected to have a capacity of 1 billion to 2 billion cubic feet per day. 5. BC LNG Export Co-Operative: Operated by Douglas Channel Energy Partnership, which is a partnership between LNG Partners and the Haisla Nation in British Columbia. There are 16 members of the cooperative. The facility is expected to have an export capacity of 100 million cubic feet per day. 6. Imperial Oil/Exxon LNG Project: Imperial Oil Ltd. and its parent, Exxon Mobil Corporation, are in the early stages of planning an LNG export business. The capacity of the facility has not yet been disclosed. 7. Prince Rupert LNG: BG Group plc and Spectra Energy Corp. are in the early stages of developing the Prince Rupert LNG project. 8. Nexen/INPEX LNG Project: Nexen Energy ULC and a consortium led by Japan’s INPEX Corporation intend to jointly investigate the feasibility of a potential downstream project, including an LNG export facility. 9. Kitsault Energy LNG Project: Kitsault Energy intends to establish an LNG export facility at Kitsault, B.C.
and there is no guarantee that any of the major projects currently under consideration and/or development in Canada will be sanctioned.” Lehrmann said it’s unclear how many projects in British Columbia will move forward. “As natural gas in Australia, the Middle East, off the coast of Africa and those places are evolving—it’s a global competition,” he noted. Inf lationar y pressures can wreak havoc on these complex projects. With so many facilities being proposed at the same time in British Columbia, it could potentially overheat the competition for labour and materials and drive up costs. Late last year, for example, Chevron added $15 billion to the cost of the Gorgon LNG export complex in Australia, which is now estimated at $52 billion. Having adequate supply, ensuring export infrastructure is in place and securing a partnership between buyers and sellers are three key ingredients to ensure Canada can tap new markets. But Kitimat LNG’s proponents have yet to ink the necessary customer agreements to sell its gas to Asia, its target market. George Kirkland, Chevron’s vice-chairman and executive vice-president, upstream, has publicly stated that the company wants at least 60–70 per cent of Kitimat LNG supply under long-term agreement before announcing a fi nal investment decision on the project. Preferentially, the company would like to see contracts tied to oil and offer buyers an equity stake in the project, Kirkland said. “It is Chevron’s position, and I believe the industry’s position, that LNG projects will require long-term pricing that underpins the significant financial investment required to monetize these resources,” Lehrmann said. “Industry and government, therefore, both have important roles to play to support new markets for Canada’s energy resources.” OIL & GAS INQUIRER • DECEMBER 2013
15
British Columbia
Black wants $8-billion federal loan guarantee on Kitimat refinery By Carter Haydu
While he expects Chinese investors to cover the majority of costs for the proposed construction of a multi-billion dollar heavy oil refi nery to be located 25 kilometres north of Kitimat, B.C., media mogul David Black said he will nonetheless be seeking a loan guarantee from Ottawa on a portion of the project. “We will ask the federal government to guarantee one-third of the total $26 billion, or about $8 billion. This guarantee that we are asking for has completely aligned with all the precedents,” Black said during the 2013 Calgary Energy Roundtable conference. “That’s what the federal government did for Muskrat Falls [hydroelectric project] for about $8 billion.” Earlier this year, the president of privately held Kitimat Clean Ltd. signed a memorandum of understanding with the Industrial and Commercial Bank of China
that would see the bank act as both fi nancial adviser to the project and provide financing for the refinery, pipelines and other elements of the project. Black said previously that he expects to have all funding under contract by early 2014.
“The polls in B.C. show, and have shown continuously for some time now, the only way a pipeline across B.C. would be accepted is if there is a refinery.” — David Black, president, Kitimat Clean Ltd.
The Black Press owner and chairman said that adding value to Alberta bitumen through a large coastal refi nery in British
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Columbia is perhaps the only way residents of Canada’s most westward province would support moving oilsands assets through their jurisdiction. “The polls in B.C. show, and have shown continuously for some time now, the only way a pipeline across B.C. would be accepted is if there is a refinery,” he said. “People don’t want just dilbit to be shipped.” According to Black, the 550,000-barrelper-day refinery project would cost a total of approximately $26 billion, comprised of $18 billion for the refinery itself, a $6-billion diluted bitumen pipeline from Edmonton to Kitimat, as well as part of the cost for a natural gas pipeline for $1 billion and a tanker fleet at about $1 billion. Because the coastal location of the refinery means it would be able to use large modular components from Asia in its construction, Black said building the
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DECEMBER 2013 • OIL & GAS INQUIRER
Photo: Joey Podlubny
British Columbia
refi nery near Kitimat would be considerably less expensive than if it were to be built in Alberta. He added the refinery would use Calgary-based Expander Energy Inc.’s Fischer-Tropsch technology that would cut CO2 emissions by half compared to a traditional refinery. “There’s a huge political gain in cutting CO2 in B.C. and right across Canada. Cutting emissions in half is enormous for us, and it would be a world first. Hopefully, once we showcase it, the technology would be used in refi neries across the world hereafter.” Black said t he benef it to British Columbia and Canada would also be tremendous, in the form of more jobs on the west coast from a refi nery adding value to Alberta oilsands products. “The refinery will create 6,000 construction jobs for five years, and for the pipelines 1,000 more. The refinery will result in more permanent jobs than any project ever created in the province. It would create at least 3,000 well-paid permanent jobs that should last 50–100 years.
The Scotford Refinery north of Edmonton. Like Shell Canada Limited’s Scotford operations, the proposed Kitimat refinery will run on bitumen.
“In addition to that, the petrochemical business usually adds about one job for every job in the refinery. We expect a lot of factories to pop up around the refinery and there is a
lot of room for it there. We could easily end up with another 3,000 direct petrochemical jobs in the valley, and it would create thousands of indirect jobs in the area.”
OIL & GAS INQUIRER • DECEMBER 2013
17
N.W.
NORTHWESTERN ALBERTA WELL ACTIVITY OCT/12
OCT/13
Wells licensed
282
OCT/12
OCT/13
Wells spudded
203
OCT/12
OCT/13
182
Rigs released
▲
▲
Northwestern Alberta
▲
Source: Daily Oil Bulletin
Shell moving forward with Carmon Creek project in Alberta Royal Dutch Shell plc is proceeding with its Carmon Creek project in the Peace River oilsands, which is expected to produce up to 80,000 barrels of oil per day, the company announced in late October. Carmon Creek is a thermal in situ project that is 100 per cent Shell owned and will be part of the company’s broader production, refining and marketing business across the full value chain in North America. “I’m pleased we’re moving ahead with this important project,” said Lorraine Mitchelmore, president and executive vice-president of heavy oil of Shell Canada Limited. “Shell’s Peace River oil leases represent a significant development opportunity. Our decision to invest in Carmon Creek has been carefully studied with the goal of designing a project that is competitive from a commercial, technological and environmental perspective.” Cogeneration and steam facilities
At Carmon Creek, Shell combined its global procurement reach and technology with access to local expertise to design a facility that is both commercially viable and minimizes environmental impacts. This design includes a novel well-delivery system and the use of cogeneration that will also feed power into the Alberta grid— enough to power half a million homes. Once the project is up and running, the aim is to virtually eliminate the need for freshwater use for steam generation through recycling of water produced with the oil. Carmon Creek will build on Shell’s more than 30 years of experience developing its Peace River heavy oil leases and established relationships with local communities and First Nations, the company said. It is expected to employ more than 1,000 local tradespeople and contractors during peak construction periods.
Purchased sweet fuel gas Treated gas
Makeup water
Recycled water
Excess power to regional grid
Diluent Gas
Pipeline gathering system
Water Bitumen
Diagram: Shell Canada Limited
Steam Inlet separation Produced water and bitumen
Bitumen, water & gas
H2S and associated CO2 to deep well disposal Central processing facilities (bitumen, water & gas treating)
Bitumen sales
Well pad (multiple vertical wells)
The production process to be used at Carmon Creek. Shell includes cogeneration facilities and the use of recycled water.
“This will be a steam flood development, in two phases of 40,000 barrels per day each. The bitumen will be exported by pipeline to east Canada and from there to refi neries for processing, for example on the Gulf Coast,” said Simon Henry, Royal Dutch Shell’s chief financial officer. Shell submitted its regulatory application for Carmon Creek in 2010 and received approval from the Alberta Energy Regulator in April 2013, following a review process. For the start-up of Phases 1 and 2, Carmon Creek will produce from 13 well pads. An inter-field pipeline system will transport steam to the wells and produce bitumen, water and natural gas that will be sent to central processing facilities. The central processing facilities will separate bitumen from water and natural gas, which can then be used to produce steam. Diluted bitumen is expected to be exported to existing North American refineries. Cogeneration units are expected to produce an annual average of up to 630 megawatts of electricity, of which about 500 megawatts is expected to be sold to the northwestern Alberta power grid. Shell said it’s taking a well manufacturing approach to drill and complete the wells using the Sirius Well Manufacturing Services joint venture. This approach is based on standardization of components and allows quicker and repeatable operations that provide opportunities to reduce costs. To minimize surface disturbance, approximately 48 wells will be closely spaced on each well pad. Each well pad will have a life of 10–15 years, and as pads come to the end of their life, the well pad equipment will be refurbished and reused on new pads and the land will be reclaimed to minimize the project footprint. As is common in heavy oil construction, modules will be built elsewhere and transported to site for fi nal assembly and commissioning, Shell stated. — DAILY OIL BULLETIN OIL & GAS INQUIRER • DECEMBER 2013
19
Northwestern Alberta
Drilling success continues for Delphi Delphi Energy Corp. said it continues to improve its drilling time and costs on its extended-reach horizontal wells. In a drilling update, the company reported that its recently completed 15-24-060-23W5 Montney well was drilled during the third quarter of 2013 to a total depth of 5,211 metres with a horizontal lateral length of 2,328 metres and stimulated with a 30-stage slickwater hybrid completion. The well was produced on cleanup over a six-day period, recovering approximately 25 per cent of the initial load frac water and is now shut-in to equip and pipeline connect the well for production. After running production tubing, the well produced over the final 2.7 days at an average rate of approximately 5.2 million cubic feet per day of raw gas, 635 barrels per day of wellhead condensate (122 barrels per million cubic feet of raw gas) and approximately 660 barrels per day of load frac water. With an expected plant natural gas liquid (NGL) yield of 33 barrels per million cubic feet of raw gas, total production over the flow period was approximately 1,585 barrels of oil equivalent per day (51 per cent field and plant NGLs). The well was expected to start production before the end of October and, consistent with the three previous slickwater fracture-stimulated wells, will continue to recover load frac water over the next few months. The follow-up location to the successful 15-24 well at 15-30060-22W5 has been drilled to a total depth of 5,834 metres with a horizontal length of 3,014 metres, making it the longest horizontal Montney lateral Delphi has drilled to date. Completion operations at 15-30 were scheduled to begin in early November after the drilling rig has moved to its next location at 15-21-060-23W5. The company continues to improve its drilling time and costs on its extended-reach horizontal wells with the most recent 15-30 well reaching its total depth in 30 days, a 36 per cent reduction in drilling time and a 20 per cent decrease in cost from the company’s initial Montney wells. The first three Montney wells at East Bigstone in 2013, stimulated with the new slickwater hybrid fracturing technique, continue to exceed the company’s expectations. The 10-27 well has produced
Delphi Montney oil fracs vs. slickwater fracs Conventional oil fracs
Horiz. length (metres)
Number of fracs
IP30 sales (boe/d)
IP90 sales (boe/d)
IP120 sales (boe/d)
IP180 sales (boe/d)
Sales at day 180 (boe/d)
16-30 well
2,760
20
1,099
790
688
558
259
05-02 well
3,005
20
969
676
584
479
250
14-23 well
2,238
20
1,570
929
795
635
291
Horiz. length (metres)
Number of fracs
IP30 sales (boe/d)
IP90 sales (boe/d)
IP120 sales (boe/d)
IP180 sales (boe/d)
Sales at day 180 (boe/d)
15-10 well
1,424
20
991
833
768
660
421
Type well
2,400– 3,000
30
1,219
1,058
997
899
646
Slickwater fracs
10-27 well
2,407
30
1,815
1,653
1,545
1,062
928
16-23 well
2,809
30
1,781
1,488
N/A
N/A
N/A
Note: Calculated on operating days; excludes non-producing days. Source: Delphi Energy Corp.
20
DECEMBER 2013 • OIL & GAS INQUIRER
Northwestern Alberta
approximately 245,000 barrels of oil equivalent (40 per cent NGLs) at an average rate of 1,364 barrels per day over the first 180 days of production. The 16-23 well has produced approximately 168,000 barrels of oil equivalent (35 per cent NGLs) at an average rate of 1,395 barrels per day over the first 120 days of production. At payout, the 16-23 and 10-27 wells are forecast to still be producing approximately 500–700 barrels of oil equivalent per day each, contributing significant free cash flow for the continued development of the Bigstone Montney project. Delphi’s second drilling rig has been rig released after completing drilling operations at 14-17-059-22W5 (surface location at 05-08-059-22W5), where a Duvernay vertical strat test well with a subsequent Montney horizontal whipstock was successfully drilled. The company has now earned a working interest in 21 sections and will earn a 75 per cent interest in all 32.5 sections of the farm-in, for the Montney and Nordegg rights, upon the Montney horizontal well being completed, equipped and pipeline connected in 2014. — DAILY OIL BULLETIN
Baytex advancing CSS enhanced recovery project By Paul Wells
Baytex Energy Corp. continues to advance its heavy oil cyclic steam stimulation (CSS) enhanced recovery project at Cliffdale in the Peace River area, and the company remains on track for first steam at its second module to occur during the first half of 2014. “We expect to recover about five to seven per cent of the original oil in place using primary methods, and using thermal technology, we think we can improve that recovery factor to about 30 per cent,” vice-president of investor relations Brian Ector told the Canaccord Genuity Global Resource Conference in October. “The capital efficiencies for thermal development are also projected to be attractive—in this case, finding and development costs of around $7 a barrel. But we are still very much in the incipient stages of our thermal development.” In 2012, the company achieved a significant milestone with the completion of its fi rst 10-well CSS module. Production during the fourth quarter of 2012 averaged approximately 400 barrels per day, and during August and September of this year, output from the module increased to about 700 barrels per day. Earlier this year, Baytex received regulatory approvals to advance a new 15-well CSS module located immediately adjacent to the current 10-well module. Facility construction began late in the first quarter, while drilling operations started late in the second quarter. “We do expect to complete construction of the plant and commence cold production during the fourth quarter. We will just place these wells on production; they will produce at small rates—20–25 barrels each—just to get voidage in the reservoir before we inject initial steam,” Ector said. “First-cycle steaming is expected to occur in the first half of 2014.” OIL & GAS INQUIRER • DECEMBER 2013
21
NORTHEASTERN ALBERTA WELL ACTIVITY OCT/12
OCT/13
Wells licensed
54
OCT/12
OCT/13
Wells spudded
143
OCT/12
OCT/13
154
Rigs released
▼
▲
▲
Source: Daily Oil Bulletin
N.E.
Northeastern Alberta
Suncor sanctions $13.5-billion Fort Hills oilsands mine By Lynda Harrison
Suncor Energy Inc. and its partners gave unanimous go-ahead for the long-planned Fort Hills oilsands mine in late October, expected to provide the company with up to 73,000 barrels per day of bitumen starting as early as the fourth quarter of 2017. “The Fort Hills economics are positive,” said Steve Williams, Suncor’s president and chief executive officer. “Great effort has been made to ensure that our depth of experience and recent technology improvements in oilsands mines are integrated into the development of the project. We are delighted that the other owners share our enthusiasm for this exciting new development.” The project is scheduled to achieve 90 per cent of its planned production capacity of 180,000 barrels per day within 12 months. The go-forward capital investment in Fort Hills is estimated at approximately
Fort Hills overview Suncor is the operator and holds a 40.8 per cent working interest (Total 39.2 per cent, Teck 20 per cent) Best estimate contingent ~3.3 billion barrels of bitumen (~1.35 billion net to Suncor) Target fi rst oil as early as Q4 2017, ramp up to 90 per cent within 12 months Design capacity 180,000 barrels of bitumen per calendar day (73,000 barrels per day net to Suncor) Regulatory approvals in place, Alberta Environmental Protection and Enhancement Act approval in 2002 Source: Suncor Energy Inc.
$13.5 billion ($5.5 billion net to Suncor) and is expected to account for approximately 15 per cent of Suncor’s total capital budget on average per year. The total project cost is estimated at a capital intensity of approximately $84,000 per flowing barrel of bitumen and is within the range of similar recently completed oilsands mining projects, said Suncor. Fort Hills Energy LP consists of three limited partners: Suncor (40.8 per cent interest), Total E&P Canada Ltd. (39.2 per cent interest) and Teck Resources Limited (20 per cent interest). Suncor is the developer and operator of the Fort Hills project, located 90 kilometres north of Fort McMurray, via an operating services contract. “The Fort Hills project is one of the best undeveloped oilsands mining assets in the Athabasca region, is an excellent fit with Suncor’s diversified production portfolio and will generate significant economic value for Suncor, Alberta and Canada,” said Williams. “Given its combination of ore quality and resource size, we expect this project will be a signifi cant source of long-term cash flow for the company and contribute strong returns for our shareholders,” said Williams. Suncor believes the project can be profitable with bitumen prices at $50–$60 per barrel. The project’s construction is expected to provide 21,000 person-years of employment in Alberta alone, with additional employment outside the province and outside Canada. Direct and indirect as well as induced employ ment is ex pected to prov ide
A lberta with 47,000 person-years of employment. Suncor and Total decided earlier this year not to proceed with the 200,000-barrelper-day Voyageur upgrader, so each of the three partners can decide where its share of bitumen will go, but Suncor believes some of its portion will be taken to upgraders in the region while some will end up as far away as the U.S. Gulf Coast, said Williams.
Suncor believes the Fort Hills oilsands mine can be profitable with bitumen prices at
$50–$60 per barrel.
He said Suncor has no market access issues. “We have plans in place which will take all of our base barrels and all of our growth barrels to market.” Bart Demosky, chief financial officer, said the project will represent on average about 15 per cent of Suncor’s anticipated capital expenditures, which is not a significant burden for the company. “All of the 2014 capital to be spent on the project will be accommodated within our estimated capital budget range next year of $7 [billion to] $8 billion,” said Demosky. Internal rate of return is estimated at 13 per cent, he added. W i t h b e s t- e s t i m a t e c o n t i n g e n t resources of approximately 3.3 billion barrels of bitumen (1.3 billion barrels net to Suncor), the mine life is expected to be in excess of 50 years at the current planned production rate. OIL & GAS INQUIRER • DECEMBER 2013
23
Northeastern Alberta
Horizon expansion making good progress, says Canadian Natural Canadian Natural Resources Limited said it completed several key milestones in the third quarter in the expansion of its Horizon oilsands mine, as well as achieving record crude oil and total production across the company. Overall Horizon Phase 2/3 construction, which is targeted to increase production capacity to 250,000 barrels per day of synthetic crude oil (SCO), reached approximately 30 per cent of physical completion with current costs continuing to trend slightly below sanctioned cost estimates, as the company executes a cost-driven strategy for expansion. The reliability phase is approximately 91 per cent physically complete and is trending approximately five per cent below the budgeted $1.09 billion. The absorber towers for the Gas Recovery Unit were safely erected and installed in September. The reliability phase will increase performance, overall production reliability and the recovery of additional light oil barrels with the Gas Recovery Unit as the company moves into 2014. The reliability phase provides additional redundancies that facilitate operating the plant more consistently and with more confidence in reliable production. Phase 2A reached a major milestone in the third quarter with the installation of coke drums 33-D-3A/B. The coke drums are approximately nine metres in diameter and stand approximately 43 metres high, and were safely lifted and installed in August. Phase 2A, which will add 10,000
Horizon oilsands production capacity plan (bbls/d) 300,000 275,000 250,000 225,000 200,000 175,000 150,000 125,000 100,000 75,000 50,000 25,000 0
Planned annual spending of approximately $ billion to $. billion for - for expansion to , bbls/d of SCO Budget
Capacity target
80 Mbbls/d added
48 Mbbls/d added 10 Mbbls/d 115 Mbbls/d added base capacity
F
F
F F F Phase A Phase B Phase
F
F
Capacity additions: 3–6 months required to ramp up to full rates. Note: Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. 2013F to 2019F based on company internal forecast as of May 2013. Source: Canadian Natural Resources Limited
barrels per day of additional SCO production at Horizon, is approximately 70 per cent physically complete and on schedule for completion in 2015. Completion of Phase 2A will use preinvested infrastructure and equipment to expand the coker plant and alleviate the current bottleneck. Phase 2B continues to progress on cost and on schedule to add a targeted additional 45,000 barrels per day of SCO in 2016. It is approximately 20 per cent physically complete and will increase bitumen yield through the addition of the vacuum distillation unit. Phase 2B will expand the capacity
of froth treatment, the gas/oil hydrotreater and the hydrogen plant. Bids are out for major components on this phase. Phase 3 continues to progress on cost and on schedule to add a targeted additional 80,000 barrels per day of SCO in 2017. It is approximately 19 per cent physically complete and will bring Horizon production capacity to 250,000 barrels per day of SCO and will result in additional reliability, redundancy and significant operating cost savings. Phase 3 will expand capacity through adding extraction trains 3 and 4. — DAILY OIL BULLETIN
Husky testing fire to extract bitumen from thin zones By Pat Roche
Husky Energy Inc. is progressing the in situ combustion pilot at its McMullen oilsands lease in northern Alberta. The company is “continuing to advance the air injection pilot and…recently brought three additional production wells on stream,” chief operating officer Robert Peabody told the company’s third-quarter results conference call. In the third quarter, the three additional horizontal production wells were tied in and 24
DECEMBER 2013 • OIL & GAS INQUIRER
Alberta Energy Regulator (AER) approval was received for them to be put on production. Husky originally applied for one production well for the in situ combustion pilot. In its January 2010 regulatory application, the company said the project is in the southwestern quarter of 35-078-25W4, about 35 kilometres south of Wabasca-Desmarais and 120 kilometres northeast of Slave Lake. The pilot would ignite and oxidize the residual oil saturation in a depleted gas cap
reservoir, thereby heating the underlying bitumen so it would flow to a production well. The original horizontal producer was designed to extract up to about 150 barrels of bitumen per day. In its 2010 regulatory application, Husky estimated the operating life of the original production well would be about eight years—roughly from 2011 to 2018. Husky didn’t release any pilot production data with its third-quarter results.
Northeastern Alberta
According to Husky’s 2010 filing, the original pilot would include a production well pad at 04-35-078-25W4 and an injection well pad at 03-35-078-25W4. The January 2010 application said the original injection well pad was to include air compression facilities, three injection wells, six observation wells and temporary steam generation facilities. The AER approved the three additional production wells last August. Husky didn’t provide any further commentary with its third-quarter results, but the fact that the company added three more production wells implies at least some optimism about the pilot’s potential. The impetus for the in situ combustion pilot stems from drilling results on the McMullen lease five years ago. Husky, the 100 per cent working interest owner, received regulatory approval in November 2008 for the McMullen cold production project. The company began by drilling nine vertical evaluation wells to test the Wabiskaw A sand unit for primary heavy oil recovery and to delineate the areal extent of the primary production area. Of those nine vertical wells, six were successful and put on primary production. The remaining three wells encountered a depleted gas-over-bitumen zone. On further evaluation, Husky concluded the three gas-overbitumen wells—particularly the 100/03-35-078-25W4 well—are in a bitumen reservoir where in situ combustion could be used to heat and produce the underlying bitumen in the Wabiskaw A reservoir. Producing bitumen from beneath depleted gas caps is typically considered risky and uneconomic. Primary production isn’t expected to be economic due to the depleted gas cap overlying the bitumen. The thin pay zones and the presence of the gas cap would hurt the economics of conventional thermal methods such as steam assisted gravity drainage and cyclic steam stimulation. In the 100/03-35-078-25W4 well, a four-metre-thick depleted gas zone overlies a six-metre-thick bitumen zone. “This depleted gas cap has very favourable reservoir parameters for igniting and maintaining a continuous combustion process based on laboratory testing conducted at the University of Calgary [U of C],” the company said in its 2010 application. The U of C tested samples of the Wabiskaw A bitumen and core from the 100/03-35-078-25W4 well. The goal was to assess the burning characteristics of the McMullen depleted gas zone at high water and low oil saturations under pressures that would be encountered in the field. Based on the encouraging results of the U of C tests, Husky decided to launch the in situ combustion pilot with a single production well. Husky said the thin bitumen zone as assessed in the 100/0335-078-25W4 well has “excellent reservoir characteristics” and is classifi ed as a homogeneous clean sand with good porosity, permeability and oil saturation. There is no underlying water in contact with the bitumen. The pilot will help Husky evaluate the commercial viability of in situ combustion as a way of recovering bitumen beneath depleted gas caps at its McMullen primary production area. But if the economics work at McMullen, the company will have demonstrated a new recovery technique that could then be tested in other oilsands areas with thin bitumen reservoirs beneath depleted gas caps. OIL & GAS INQUIRER • DECEMBER 2013
25
CENTRAL ALBERTA WELL ACTIVITY OCT/12
OCT/13
Wells licensed
288
OCT/12
OCT/13
Wells spudded
225
OCT/12
OCT/13
221
Rigs released
C.A.B.
▲
▲
Central Alberta
▼
Source: Daily Oil Bulletin
Williams Energy propane project could be just the beginning of petrochemical growth By Elsie Ross
Williams Energy (Canada) Inc. sees its Redwater, Alta., $900-million propane dehydrogenation (PDH) project, which will produce polymer-grade propylene, as just the first step in adding value to propane in Alberta, a conference heard in October. “What we would like to see is to attract a propylene derivative to Alberta to create a demand for propylene right here,” said Amelie Delisle, PDH business manager. “That would eliminate the need to rail propylene to the Gulf Coast and further upgrade what started out as propane here,” she told the 20th annual joint conference of the Gas Processing Association Canada and the Petroleum Joint Venture Association. “A propane derivative would create a higher-value product that would allow access to multiple markets, either in North America or internationally.” It would also provide market flexibility and enable it to move away from depending on a single customer or region for its product, said Delisle. Williams has seen considerable interest from a number of parties as it explores
Alberta propane supply and demand
Supply and demand (103 m3/d)
Actual
Forecast
Supply and demand (103 bbls/d)
opportunities to attract derivatives players to build a plant in close proximity to its PDH plant, which should be in operation in 2017, she said. “We see a lot of options and a lot of applications for propane derivatives and we think it’s a good value proposition.” As a derivative, polypropylene accounts for by far the largest demand (55 per cent) for propylene in the United States, the conference heard. A form of plastic, it is used in car parts and food containers. Propylene oxide (13 per cent of propylene demand) is further upgraded into products such as polyurethane and propylene glycol, which can be used in the food and pharmaceutical industries. Propylene glycol can also be used as an aircraft de-icing fluid. “We think that could be a nice fit here as we currently are railing all our de-icing fluids from the U.S. Gulf Coast,” said Delisle. “It seems like a lot of transportation to send the propane down south to have it come back.” A third derivative, which accounts for about 10 per cent of propylene demand, is
Supply
Alberta demand
Source: Alberta Energy Regulator
acrylonitrile, which is transformed into fibres (acrylic). A fourth derivative (seven per cent of demand) is acrylic acid, a super-absorbent polymer used in disposable diapers. Based on September 2013 prices, propylene is worth about three times that of propane and there are further price advantages with further upgrading, Delisle said. The feedstock for the PDH project will come from off-gases produced by the Suncor Energy Inc. and Canadian Natural Resources Limited Horizon oilsands mine upgraders at Fort McMurray. Williams already extracts a mixture of natural gas liquids and olefins from the Suncor upgrader off-gases and replaces it with natural gas before transporting the remaining mixture to its Redwater fractionator via the Boreal Pipeline. The PDH plant, the first of its kind in Canada, will produce 1.1 billion pounds of propylene per year. The site near Redwater was selected because there are five nearby fractionators that also produce propane, said Delisle. “We are going to need lots of propane for this.” In the next few years, “we are going to be awash in propane,” she said. In addition to increased fractionation capacity in Alberta in response to the growth in liquids-rich plays, the rise in propane production in the United States means there are more limited export markets for Canadian propane. The reversal in 2014 of Kinder Morgan Canada Inc.’s Cochin Pipeline to import condensate instead of exporting propane will also limit export access, the conference heard. While some propane will be exported, Williams’ PDH plant will provide another market for the propane, said Delisle. “A lot of that propane being exported will end up being upgraded elsewhere, so why not capture some of that here?” OIL & GAS INQUIRER • DECEMBER 2013
27
Central Alberta
Encana pushing Duvernay toward commercialization By Pat Roche
Encana Corporation released impressive Duvernay well results in October, but anyone hoping the shale play will significantly boost the company’s liquids output must await future disclosures. In reporting its third-quarter results, Encana said its 8-5 Duvernay well in westcentral Alberta had an initial production rate of 1,400 barrels per day of field condensate and four million cubic feet per day of natural gas over its first 30 days, and 350 barrels per day of condensate and two million cubic feet per day of gas after 160 days, all volumes after royalties. Encana said it has completed 12 horizontal wells in the Duvernay Formation, with 10 on production and two being tied in. Condensate yields range between 45 and 300 barrels per million cubic feet. But in Encana’s third-quarter results, the Duvernay is lumped with “other and emerging” plays under both gas production and oil and natural gas liquids production.
wheRe dO we PUT
The Duvernay is still “an emerging play being evaluated,” but “we have a clear line of sight to taking that commercial, declaring it commercial and growing it into next year,” said Mike McAllister, Encana’s executive vice-president and president of its Canadian division. “We’re very encouraged on the well results we saw up in Simonette with over 1,000 barrels per day on our latest well that’s still cleaning up,” McAllister told the company’s quarterly earnings conference call. Doug Suttles, Encana’s president and chief executive officer, added: “I think that we’re obviously very encouraged by what we see in the Duvernay. And one of the things we’re working on quite hard now is how quickly can we ramp that up? I think the current forecast isn’t fast enough. And one of the areas of focus is how do we make that faster? And a lot of that is finding a good midstream solution. So it’s really tied up in a lot of our strategy work right now.”
Chevron Corporation also reported encouraging results following the conclusion of an initial exploration phase by its Canadian subsidiary, Chevron Canada Limited, in the Kaybob area of the Duvernay play, located in west-central Alberta. Chevron Canada successfully concluded the initial 12-well exploration drilling program in the liquids-rich portion of the Duvernay shale play. Five wells have been completed and are tied into production facilities, and an additional four wells are waiting on completion and tie-in. The company said its acreage is well positioned in the condensate-rich and volatile oil portion of the play. Liquids yield for the completed wells range from 30 to 70 per cent with initial production rates up to 7.5 million cubic feet of natural gas per day and 1,300 barrels of condensate per day. “Early results of our Duvernay exploration program are encouraging,” said George Kirkland, vice-chairman and executive
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DECEMBER 2013 • OIL & GAS INQUIRER
Central Alberta
Encana’s Duvernay operations
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Land (net acres): 253,000 Average working interest: 50 per cent RPH type curve EUR/well: 1,000–1,200 mboe RPH type curve ROR: 100 per cent Well inventory (gross): 1,420 RPH well costs (DCT): $12 million to $18 million Royalty rate: 15 per cent 2013F exit rate (net): Oilfield condensate: 1,300 bbls/d NGLs: 230 bbls/d Natural gas: 10 mmcf/d Supply cost: < $1.00/mcfe, $40–$60/boe Source: Encana Corporation
vice-president, upstream, of Chevron. “This discovery creates a foundation for future growth in Canada.” “Well performance and condensate yields exceeded our expectation and strengthen our plans going forward. Near-term plans include transitioning to a two-rig drilling program to optimize well and completion design, and full field spacing requirements,” added Jeff Shellebarger, president of Chevron North America Exploration and Production Company. With the acquisition of Alta Energy, Inc. and affi liates’ acreage announced earlier this year, Chevron now has approximately 325,000 net acres in the Kaybob area of the Duvernay play. “The Duvernay is a very attractive development area and Chevron continues to be very encouraged by reservoir and performance data from results to date,” said Leif Sollid, a Chevron spokesman. “The company is planning an appraisal program which will be executed prior to full development. Goals of the appraisal program include optimizing well design, well spacing requirements and completions design.” Asked whether comparisons with the Eagle Ford are still fair, he said that the Duvernay is similar to Eagle Ford in that it is a wet condensate shale play, with gradations of fluid content and distinct higher-value sweet spots. “Eagle Ford is considerably more mature in its development cycle,” Sollid said. “Chevron expects Duvernay to follow a similar path, and believes Chevron’s acreage is nicely located in the best part of the play.” He added the company is not in a position to disclose at this time how many wells it plans to drill next year. The appraisal program will start in the second half of 2014. According to a report by ITG Investment Research, the higher liquids portion of the Kaybob South region’s gas condensate window is the most attractive area, based on the group’s interpretation of geology and operator activity. West Shale Basin activity and well results lag because of a lower-quality reservoir and drilling challenges, but licensing was recently ramping up in the Willesden Green area. “This indicates operators are hoping to improve on results, in our opinion,” ITG stated. Duvernay mergers and acquisitions transactions averaged roughly $7,500 per acre for the past year, with peak prices approaching $10,000 per acre. This lags the Eagle Ford’s per-acre benchmark of $15,000–$25,000 for core acreage, the report stated. The Duvernay and Eagle Ford have similar-sized footprints. The Duvernay dips to the southwest, but not as steeply as the Eagle Ford, “resulting in wider product windows in the Alberta play.”
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SOUTHERN ALBERTA WELL ACTIVITY OCT/12
OCT/13
Wells licensed
52
OCT/12
OCT/13
Wells spudded
92
OCT/12
OCT/13
96
Rigs released
▼
▼
▼
Source: Daily Oil Bulletin
S.A.B. Southern Alberta
Twin Butte to acquire Black Shire for $358 million
Photo: Joey Podlubny
Twin Butte Energy Ltd. has entered into an arrangement agreement to acquire Black Shire Energy Inc. for total consideration of approximately $358 million, including the assumption of approximately $107.6 million of net debt. Black Shire is a private company with a focused asset base in the greater Provost area of Alberta, producing approximately 7,000 barrels of oil equivalent per day (93 per cent medium-gravity oil). The greater Provost area is directly adjacent to Twin Butte’s core Lloydminster heavy oil area. Twin Butte said Black Shire is an attractive acquisition for the company as it has demonstrated its ability to generate substantial free cash flow while developing its large and lowrisk horizontal drilling inventory, providing growth in production and reserves. Twin Butte believes that the Black Shire acquisition strategically supports its dividend model and enhances the company’s long-term dividend sustainability. Black Shire was formed in 2010 by president and chief executive officer Suzanne West with equity financing from Lime Rock Partners, a global energy-focused private equity firm.
Fracking crew working in southeastern Alberta.
Key attributes of Black Shire include: • Solid production base, low decline, high netbacks: Current production of approximately 7,000 barrels of oil equivalent per day with less than a 20 per cent decline. Medium-gravity crude oil currently generating in excess of $40-perbarrel netbacks, a signifi cant increase over Twin Butte’s current heavy oil netbacks of $22 per barrel. Most production is operated, the majority being 100 per cent working interest. Twin Butte said acquisition metrics are attractive at $49,000 per producing barrel, net of its internal assessment of Black Shire’s undeveloped land value. • Concentrated land base, operatorship, high working interest: Lands associated with the Black Shire acquisition compr ise over 159 net sections in one concentrated area in the Provost area. Net undeveloped lands in excess of 40,000 acres, combined with Black Shire’s operated, mostly 100 per cent working interest production and infrastructure, are expected to provide Twin Butte with a significant new operational focus and a platform for
future growth in the Provost area. Twin Butte has valued Black Shire’s net undeveloped lands at approximately $13.6 million ($340 per acre). Twin Butte will also receive a signifi cant seismic database of 160 kilometres of 2-D data and 140 square kilometres of 3-D data. • High-quality reserves: The Black Shire acquisition includes proved reserves of 12.6 million barrels and proved-plusprobable reserves of 20.01 million barrels based on an independent reserve report effective Dec. 31, 2012. The pre-tax present value of the provedplus-probable reser ves discounted at 10 per cent as of the report date was $464 million. This equates to an attractive acquisition price of $17.90 per proved-and-probable barrel generating an associated recycle ratio of over two times. • Extensive infrastructure and development drilling opportunities: Black Shire owns extensive oil, gas and water-handling infrastructure with excess capacity providing the opportunity for Twin Butte to quickly enhance productivity through infield drilling opportunities. Ownership and operatorship in the extensive infrastructure has allowed Black Shire to maintain a comparatively strong operating cost structure currently under $18 per barrel. Twin Butte has identified an infill drilling inventory of over 100 wells on the Black Shire lands. Tw i n But te’s st rateg y of prov iding shareholders with long-term total returns comprised of both income and moderate g row t h is ex pec ted to be strengthened through the Black Shire acquisition by: • Reducing Twin Butte’s anticipated annual production decline rate to 26 per cent from 29 per cent; • Enhancing Twin Butte’s netback from current levels of $22–$27 per barrel; OIL & GAS INQUIRER • DECEMBER 2013
31
Southern Alberta
• Increasing Twin Butte’s liquids production weighting to 90 per cent from 88; and, • Reducing Twin Butte’s all-in payout ratio to 90 per cent from 100. Including expected maintenance capital required on the subject assets, the Black
Shire assets are expected to generate cash flow that will significantly exceed the capital required to off set expected declines and pay the dividend associated with the Twin Butte shares to be issued in connection with the acquisition and the bought deal fi nancing.
Twin Butte believes that the Black Shire acquisition will strengthen the long-term sustainability of the company’s dividend by reducing declines and enhancing netbacks, all while maintaining Twin Butte’s low-capital efficiencies of under $20,000 per barrel per day. — DAILY OIL BULLETIN
Calgary utility says gas-fired power set to increase By Carter Haydu
While there will continue to be a role for coal in the future, Gianna Manes, president and chief executive officer of ENMAX Corporation, said she sees North America largely replacing aging plants with those that burn natural gas, and the impact on the upstream gas industry could be tremendous. “If we were to transition from all the coal plants that are expected to retire across North America to natural gas plants, as we believe a good majority of them will, then the natural gas consumption just
32
DECEMBER 2013 • OIL & GAS INQUIRER
for the power sector will increase by as much as 1.4 [billion] to 2.4 billion gigajoules annually.” Manes told this week’s 2013 Calgary Energy Roundtable conference the most likely way to replace an aging fleet of coalfired power plants is for companies to replace those plants with natural gas–fired ones. “For a number of reasons, as we move ahead, we really see this transition taking place substantially with gas over the next decade.”
According to Manes, about 15 per cent of electricity generation in Canada comes from coal, with coal-fired electricity in Saskatchewan and Alberta accounting for about 75 per cent and 70 per cent, respectively. In the United States, about 37 per cent of electricity comes from coal. Manes noted that, on average, Canada’s coal-fired plants are about 36 years old, while in the eastern United States where the majority of North American coal-fi red power plants are located, the average age is
Southern Alberta
about 50. Therefore, she said, those plants are nearing the point where they need to be replaced. The greenhouse gas levels associated with older coal-fi red power plants is another reason for their impending replacement, she said. Environmental regulations in Canada and the United States with regard to coal plants have much more teeth in them in terms of enforcement than they did 15 years ago, she said. “Fifteen years ago, there was a lot of talk about what we saw emerging, but the regulations there were tied up in [the] courts and they really did not have a lot of teeth that they currently do today.” A lt hough power companies have known for several years that they would have to replace their aging coal-fired plants, Manes said volatile swings in commodity prices for natural gas served as a disincentive to investing in gas generation until fairly recently. She added that companies have historically been afraid to take the risk of price uncertainty within the natural gas context.
“Many companies proceeded because it was the best option on the table, but this concept really did provide some pause for many companies. This potential, of course, coupled with the recent recession we had beginning in 2007, really did temper some companies from moving forward with gas plants, particularly those companies in the regulated utility space.” However, with the economy recovering from the recent recession and the shale gas revolution vastly increasing the supply of natural gas and stabilizing prices, Manes said companies are again looking to expand generation fleets, and the use of natural gas is largely considered as a viable option for these plants. “With the availability of shale gas and the volume of gas that is out there, and what appear to be lower and stable gas prices going forward, companies are now less hesitant.” Manes said that companies have not “written off coal” though, as the nature of the electricity industry means that providers prefer to have a variety of fuel sources for their power.
It will take an increasing amount of natural gas to keep Saskatchewan’s economy fired up.
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“Traditionally, electricity companies like to approach their supply of generation from a portfolio perspective, and having a different mix of fuels in that portfolio is a more comfortable place to be in terms of being able to use different types of technology to be able to really protect against movements in prices.” Manes said it is likely companies would look at retrofitting newer coal plants across North America to use natural gas as fuel. However, she said, a large number of the coal plants currently in operation are simply too old to justify expensive retrofitting and require outright replacement. “When you start talking about hundreds of millions of dollars on the back of a plant that is so old, that is when a conversation really starts, because when you compare that to the cost of building a brand new, effi cient gas plant that has less risk, then I’d say it is more likely to withstand increasing environmental challenges in the future—and the new gas plants win.”
Saskatchewan continues to experience rapid economic growth year after year. Potash mines are multiplying across the Province, construction cranes are rising above our cities, and power plants are increasing their capacities. Each mine, industrial site, refinery, or office building needs a dependable supply of natural gas to power its expansion and future operation. TransGas is strategically positioned to provide safe and reliable natural gas transportation and storage services to support this unprecedented growth in Saskatchewan.
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33
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now so you don’t think some mad hackers kidnapped our website and made it beautiful behind our backs. Besides the improved look, we’ve added a lot of new features and navigation tools. You’ll also see a more continuous stream of stories onto the website. For a sneak peak, visit... dailyoilbulletin.com/FirstLook
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SASKATCHEWAN WELL ACTIVITY OCT/12
OCT/13
Wells licensed
423
OCT/12
OCT/13
Wells spudded
399
OCT/12
OCT/13
388
Rigs released
▲
▲
Raging River bulks up in Dodsland Viking
Photo: Joey Podlubny
Raging River Exploration Inc. has entered into an agreement to acquire properties located in the Dodsland area of southwestern Saskatchewan for $105 million. The company has also entered a freehold leasing arrangement, also in the greater Dodsland area, with a senior energy producer, and increased its 2013 development capital budget to $165 million from $145 million. Including the acquisition of 900 barrels of oil equivalent per day (83 per cent light oil) and the $20-million capital budget expansion, Raging River now expects to exit 2013 at approximately 8,000 barrels per day (96 per cent oil). This represents an increase of 27 per cent from the Aug. 14, 2013, exit guidance of 6,300 barrels per day. Based on field receipts, third-quarter production was approximately 5,650 barrels of oil equivalent per day, including 5,450 barrels per day of oil and 1,200 thousand cubic feet per day of natural gas, an increase of over 1,000 barrels per day of light oil from the second-quarter levels. Although the acquisition will have a nominal impact on the company’s 2013
S.K. Saskatchewan
▲
Source: Daily Oil Bulletin
average guidance, the continued success of Raging River’s drilling program has resulted in increasing average 2013 guidance by a further five per cent to 5,400 barrels per day. Through the acquisition and freehold arrangement, Raging River said it is acquiring an elite Viking light oil waterflood asset consisting of 900 barrels per day (85 per cent light oil) of production and 40.3 net sections of highly prospective land targeting Viking oil. The total drilling inventory associated with the deals includes over 280 net drilling locations, of which 95 per cent are currently unbooked. The acquired assets have estimated proved reserves of 3.4 million barrels and proved-plus-probable reserves of 4.63 million barrels (97 per cent Viking light oil). Additional acquisition metrics include production of $116,500 per producing barrel; proved-plus-probable reserves of $22.70 per barrel; and a proved-plusprobable recycle ratio of 2.2 times. The acquisition is anchored by 3.8 million barrels of producing reserves and a low decline rate of 10 per cent per year.
Horizontal infill drilling in conjunction with waterflood optimization by the previous operator of these lands has shown potential to achieve material increases in recovery factors. Utilizing the experience gained from drilling in excess of 270 Viking horizontal oil wells, Raging River intends to optimize the infill drilling and waterflood strategy to add material reserves and production from the acquisition over the next 12–18 months. The freehold arrangement includes approximately 24.5 net sections of highly prospective land targeting Viking light oil in the Forgan area with a multi-well drilling commitment over the next two years.
Raging River acquisition summary Production: 900 boe/d Average decline rate: 10 per cent per year Proved reserves: 3,420,000 boe Proved-plus-probable reserves: 4,625,000 boe Land prospective for Viking oil: 10,000 net acres Total risked drilling locations: 120 horizontal Current operating netback: $49/boe Source: Raging River Exploration Inc.
The total land base is 15,800 net acres. Total risked drilling locations are estimated at 160 net horizontal wells (100 per cent unbooked). The freehold arrangement provides a cornerstone for Viking light oil development in the Forgan prospect area, which is approximately 25 miles southeast of Raging River’s existing Plato production. The lands have been strategically selected to offset existing horizontal Viking oil wells. Similar to its past experiences, Raging River said it intends to utilize its proven strategy to improve rates, reserves and economics from this developing area. Raging River now expects to exit 2013 at approximately 8,000 barrels per day (96 per cent oil).
— DAILY OIL BULLETIN OIL & GAS INQUIRER • DECEMBER 2013
35
Saskatchewan
Surge acquires light oil assets In two separate deals announced in October, Surge Energy Inc. acquired light oil assets in Saskatchewan and Manitoba for a total cost of $282 million. The first acquisition involves the $147-million purchase of all of the shares of a Calgary-based private oil and gas company with high-netback, operated, producing light oil assets focused in t he Steelma n a rea of sout heaster n Saskatchewan and the Dodsland area of southwestern Saskatchewan. Additionally, Surge has entered into an agreement to acquire high-quality, highnetback, operated, producing light oil assets primarily located in the southwestern area of Manitoba. Total consideration of $135 million to be paid to the vendor of the Manitoba assets is comprised of 14.2 million shares of Surge and $50 million in cash. The acquisitions fit squarely within Surge’s defined business strategy of investing growth
Surge operational guidance () Before acquisitions
After aquisitions
2013E exit production (boe/d)
, (% oil/NGLs)
, (% oil/NGLs)
2014E average production (boe/d)
, (% oil/NGLs)
, (% oil/NGLs)
2014E exit production (boe/d)
, (% oil/NGLs)
, (% oil/NGLs)
. mmboe
. mmboe
2P reserves RLI (based on 2013E exit production) 2014E capital spending 2014E wells drilled 2014 decline
> years
> . years
$ million
$ million
wells
. wells
%
% Source: Surge Energy Inc.
capital to acquire elite, operated, light- and medium-gravity crude oil reservoirs, with large original oil in place (OOIP) and low recovery factors. The private company acquisition provides a strategic entry point for Surge into the prolific Midale Marly light oil play trend in southeastern Saskatchewan, and the Viking light oil play in southwestern
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Saskatchewan. The Manitoba assets provide Surge shareholders with exposure to one of the highest-quality, highest-netback light oil plays in Canada, focused in the Bakken/Three Forks formation located in southwestern Manitoba. The acquisitions provide the company with exposure to three of the top light oil plays in Canada. They also provide an
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DECEMBER 2013 • OIL & GAS INQUIRER
Saskatchewan
M
MPI
AR MIT NC PLASTICS I
..
excellent operational platform for additional growth on these proven trends. The acquisitions comprise and possess large OOIP reservoirs, together with low recovery factors, operatorship and high working interests. They also possess significant upside from low-risk development drilling and waterfloods. Furthermore, the acquisitions include key producing infrastructure, including batteries, pipelines and waterflood facilities. Post closing, Surge will have over one billion barrels of lightand medium-gravity OOIP under the company’s ownership and management, with a recovery factor of less than three per cent. Combined, the acquisitions provide proven-and-probable (2P) reserves of 9.7 million barrels (greater than 98 per cent light oil). Based on current production, the acquisitions have a long reserve life index of approximately 9.2 years (2P). Current production relating to the acquisitions is approximately 2,900 barrels per day, composed of more than 98 per cent light, sweet crude oil (38 degrees API). Surge has identified 218 (184.4 net) low-risk development drilling locations on the lands comprising the assets. The company has also identified significant unbooked waterflood upside in relation to the assets. In this regard, two waterflood projects have already been initiated on the assets. The acquisitions possess key producing infrastructure, including batteries, pipelines and waterflood facilities. The assets are 95 per cent operated, and have average working interests of greater than 90 per cent.
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Tuscany Energy updates west-central Saskatchewan program Additional output from three heavy oil wells in west-central Saskatchewan has increased Tuscany Energy Ltd.’s average production rate to approximately 750 barrels of oil equivalent per day (76 per cent oil production). Tuscany holds a 60 per cent working interest in two new wells at Evesham, Sask., which were placed on production in August 2013 at rates of approximately 170 barrels of oil per day each. To date, the wells have produced over 7,000 barrels of oil each and are currently producing at rates of approximately 170 barrels of oil per day and 160 barrels of oil per day. The company said it is encouraged by the initial production rates of the two Evesham wells, which are the best rates encountered in the pool to date. At Macklin, Sask., Tuscany has a 100 per cent working interest in a new well also placed on production in August. The Macklin well has produced over 3,500 barrels of oil and is currently producing at a rate of approximately 55 barrels of oil per day. Tuscany said it plans to continue its development program in this area with additional drilling before year-end. — DAILY OIL BULLETIN OIL & GAS INQUIRER • DECEMBER 2013
37
8.5 MILLION BARRELS PER DAY 8.5 MILLION BARRELS PER DAY
TRANS MOUNTAIN TRANS MOUNTAIN TRANS MOUNTAI
MARCELLUS SHALE MARCELLUS SHALE MARCELLUS
FIVE BILLION CUBIC FEET PER DAY FIVE BILLION CUBIC FEET PER
A
S
O
N
D
2013
Horn River (British Columbia) Montney (British Columbia & Alberta)
2.0
$3.0 $2.5 $2.0
1.5
$1.5
1.0
$1.0
0.5
$0.5
Jan05
Jan06
Jan07
Jan08
Jan09
Jan10
Jan11
Jan12
Jan13
$0
J
F
M
Source: U.S. Energy Information Administration
power generation from 25 billion cubic feet in 2012 to 21.6 billion cubic feet in 2014. Despite the recent downward trend in prices, Calgary-based FirstEnergy Capital Corp. remains committed to its outlook for higher prices. “We remain unapologetically price bullish for 2014,” Martin King, FirstEnergy’s vice-president of institutional research, told the investment fi rm’s Energy Market Update breakfast late this fall. “There is enough information out there that says the market is becoming structurally tighter now than it was just a few months ago. There’s a lot more things happening on the demand side where the market, at least in our opinion, is looking far too complacent with current prices and
forward prices,” he said. “The view seems to be that the past is a good predictor of the future. That’s never the case. It’s certainly not the case with natural gas.” First Energy expects AECO gas prices to average $3.79 per gigajoule in 2014, up from an estimated $3 this year. In the fourth quarter of this year, FirstEnergy expects AECO prices to average $2.93 per gigajoule. Unlike the EIA, King expects continued growth in consumption at U.S. gas-fired power plants, which he says could add another three billion to four billion cubic feet per day of demand. He also cited “steady growth in the so-called renaissance for industrial gas demand” in the United States, exports of gas
A
M
J
J
Source: Canadian Natural Gas Focus
to Mexico from the United States and the “pending huge pull” of gas out of the United States via liquefied natural gas (LNG) exports “in the next 24 months or so.” King said ongoing announcements of coal-fired power plants to be decommissioned are adding up to a significant shortfall in future U.S. power generation capacity, which he expects will be made up by gas. “So there’s a lot more growth coming here, and I see other more aggressive numbers out there,” he said of U.S. power demand. And although U.S. gas exports into Mexico aren’t new, King said the volumes are about to become more significant. Pipelines are being built across the border from Arizona, Texas and New Mexico to
OIL & GAS INQUIRER • DECEMBER 2013
39
PERMIAN PERMIAN PERMIAN PERMIAN PERMIAN PERMIAN
SWAN HILLS SWAN HILLS SWAN HILLS SWAN HILLS SWAN HILL
AECO $3.50 AECO $3.50 AECO $3.50 AECO $3.50 AECO $3.50 A
MULTISTAGE FRACKING MULTISTAGE FRACKING
Billion cubic feet per day
2012
$4.0 $3.5
2.5
0
Cover Feature
AECO price (C$/GJ)
January 2005 - May 2013
3.0
MINING MINING MINING MINING MINING MININ
WILRICH WILRICH WILRICH WILRICH WILRICH WILRIC
HORIZONTAL DRILLING HORIZONTAL DRILLING HORIZONTAL DRILL
BAKKEN BAKKEN BAKKEN BAKKEN BAKKEN BAKKEN
HORIZON HORIZON HORIZON HORIZON HORIZON HORIZO
KEARL KEARL KEARL KEARL KEARL KEARL KEARL KEARL KE
CARMON CREEK CARMON CREEK CARMON CREEK C
LNG LNG LNG LNG LNG LNG LNG LNG LNG
HORN RIVER HORN RIVER HORN RIVER HORN RIVER HORN RIV
LINE 9 REVERSAL LINE 9 REVERSAL LINE 9 REVERSAL LINE 9 REVERS
EAGLE FORD EAGLE FORD EAGLE FORD EAGLE FORD EA
CONDENSATE CONDENSATE CONDENSATE CONDE
CHINA CHINA CHINA CHINA CHINA CHINA CHINA CHINA
JAPAN JAPAN JAPAN JAPAN JAPAN JAPAN JAPA
FORT HILLS FORT HILLS FORT HILLS FORT HILLS FORT HILLS
MUSKWA MUSKWA MUSKWA MUSKWA MUSKWA MUSKWA
PERMIAN PERMIAN PERMIAN PERMIAN PERMIAN PE
AECO $3.50 AECO $3.50 AECO $3.50 AECO $3.50 AEC
MINING MINING MINING MINING MINING MINING
HORIZON HORIZON HORIZON HORIZON HORIZON HORIZON
Gross withdrawals from select shale plays in Canada
OUTLOOK
OUTLOOK
Natural gas forecast (2014) Alberta reference average price C$/mcf
Alberta AECO average price C$/mcf
Alberta AECO average price C$/mcf
B.C. Direct Stn. 2 sales C$/mcf
Sask. Direct Plant Gate sales C$/mcf
NYMEX C$/mcf
NYMEX C$/mcf
Current
Real
Current
Current
Current
Real
Current
2013
$2.75
$3.00
$3.00
$2.70
$2.95
$3.80
$3.80
2014
$3.25
$3.45
$3.50
$3.20
$3.45
$4.00
$4.10
2015
$3.80
$3.90
$4.05
$3.75
$4.00
$4.20
$4.35
2016
$4.10
$4.10
$4.35
$4.05
$4.30
$4.40
$4.65
2017
$4.40
$4.30
$4.65
$4.35
$4.60
$4.60
$5.00
2018
$4.85
$4.60
$5.10
$4.80
$5.05
$4.90
$5.40
Source: Deloitte LLP
feed Mexico’s industrial and power generation demand. Because Mexico hasn’t been able to increase domestic gas production, its demand has become a big driver in the U.S. market. “The amount of pipe going in the ground adds up to capacity of at least 2.5 billion cubic feet a day on stream by late next year,” King said, adding that this estimate is “probably fairly conservative. You could easily add, I’d say, another half a billion cubic feet a day.” Some pundits are suggesting U.S. gas exports to Mexico could go as high as five billion cubic feet per day by the end of next year, he said. “I think that’s a bit of a stretch, but overall, the numbers are definitely growing. Mexico needs more gas.” Meanwhile, U.S. LNG exports to overseas markets “are going to start taking off in late 2015, early 2016,” King said. “You’re going to get at least two billion cubic feet a day.” He said four U.S. LNG projects now have federal approval to export gas to countries that don’t have a free-trade agreement with the United States. “So when you factor all that stuff together, you could be looking at something closer to five billion cubic feet a day
40
DECEMBER 2013 • OIL & GAS INQUIRER
by 2018,” he said. “And there is a possibility you could get anywhere from eight [billion] to 10 billion cubic feet a day of LNG exports by the end of 2020.” Analysts are also expecting Canadian demand to pick up for the remainder of the decade. Ziff Energy Group, a division of Dallas-based energy consultancy HSB Solomon Associates LLC, expects LNG developments on the west coast and demand from Alberta’s oilsands to begin to burn off excess supply. B.C. natural gas demand could rise to more than four billion cubic feet per day by 2020 from less than one billion cubic feet per day currently if LNG exports begin in 2018, says Ziff Energy’s Growth of North American Natural Gas Demand to 2020 forecast. The B.C. figure obviously depends on gas liquefaction facilities being built in that time frame, notes Bill Gwozd, Ziff Energy’s senior vice-president of gas services. Alberta, which currently burns huge quantities of gas for power generation and accounts for about 40 per cent of Canada’s gas consumption, will need between five billion and six billion cubic feet per day in 2020, up from about 3.4 billion cubic feet per day at present, Gwozd says. “It’s big growth. And I would say 90 per cent is coming from the oilsands,” he says. But with gas exports to the United States falling, western Canadian producers are
struggling with low prices, and the situation isn’t helped by sagging coal prices that are making coal more competitive with gas for U.S. electricity generation. Gwozd acknowledges low coal prices may be an issue in the short term, but he expects coal’s market share to shrink over the long term as governments address climate change concerns. Thus power producers will more carefully scrutinize capital allocation decisions to expand or improve existing coal-fired power plants. As older coal-fired power plants are phased out, that generating capacity will be replaced by gasfired facilities, creating bigger markets for gas, he says. Ziff Energ y ’s North A merican gas forecast has demand growing in most regions and not shrinking anywhere. The forecast looks at the outlook to 2020 for six U.S. regions and Canada. It predicts very strong demand growth in Canada and the Southwest region of the United States. The Interior West of the United States is forecast to see moderate growth, while the Midwest and Northeast will experience minor gas demand growth. The Southeast and Pacific Coast are expected to be flat. The even better news is Ziff Energy expects North American gas consumption will finally hit the elusive 30-trillion-cubic-feet-per-year mark in 2016 or 2017, potentially providing relief for western Canadian producers before LNG exports begin.
OUTLOOK
Paul Ziff, executive vice-president of Ziff Energy, says the new demand will help prices, but “we see gradual improvement; I would emphasize gradual as opposed to precipitous.” He doesn’t expect the start of LNG exports to steeply increase western Canadian gas prices because the proposed projects will be supplied from dedicated unconventional resources—such as the Horn River shale play—which will be developed for that purpose. “So from our perspective, it’s very necessary for the Canadian gas producers to be very cost competitive, both on the fi nding cost and on operating cost, rather than hoping that price will be the saviour down the road,” he advises. Texas-based Solomon’s Canadian division, headed by Ziff, says the full-cycle cost of Canadian gas is more than double the cash cost. In most of the plays, the bare minimum gas price needed is $4 per thousand cubic feet and “$5-plus is more what’s required,” Ziff says. Global analysts Wood Mackenzie Limited also see improving demand for western Canadian gas beginning to ramp up, starting in 2015. But that growth will be tempered by production growth in the northeastern United States. “Our overall short-term and long-term North American gas forecast and views are largely going to be dependent on the production outlook in the Marcellus and the Utica in the northeastern region of the U.S.,” senior supply analyst Eric Kuhle says. “Very strong growth is expected to continue in the Northeast, driven by the continued expansion of the Marcellus, but over the next three to five years with an expansion and acceleration of Utica gas production as well.” Kuhle says that the U.S. northeastern plays will account for 60 per cent of North American natural gas production growth to 2020, topping out at about 14 billion cubic feet per day and surpassing the U.S. Gulf region as the leading North American gas supply area. “This is occurring as we see a very strong demand growth story in the second half of the decade, which will also support continued growth recovery in the WCSB [Western Canadian Sedimentary Basin],” he says. Although the WCSB has faced sustained natural gas production declines over the last five to seven years, Kuhle says that Wood Mackenzie sees this decline levelling off
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OUTLOOK
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Our long-term expectation for gas prices in 2020 is $5.20 real. We think that price and the price appreciation we see post-2020 start to incent development in non-core areas in the WCSB, starting to bring in areas outside of just the Montney and Duvernay in our production outlook.
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over the next few years, with the basin becoming a “growth story in the second half of the decade.” Kuhle notes that the growth will largely be supported by continued expansion in the Montney, “which has very low and attractive gas break-even rates,” supported by the liquids-rich nature of portions of the play. “In addition, we see continued investment occurring in the Duvernay shale and production growth accelerating for 2015 and beyond as companies move from delineation to development over the next several years,” Kuhle says. “The WCSB is a growth story in our long-term outlook, both from 2015 to 2020, but beyond 2020 when we see a recovery in Horn River development as our gas prices exceed $5.20 per million Btus [British thermal units] on an average basis.” Wood Mackenzie forecasts that Montney output will double from current levels to 5.1 bi llion cubic feet per day by 2018, while Duvernay production will rise to 2.1 billion cubic feet per day by 2020. Wood Mackenzie upstream research analyst Mark Oberstoetter says improving natural gas prices would spur on additional WCSB gas development early next decade. “Our long-term expectation for gas prices in 2020 is $5.20 real. We think that price and the price appreciation we see post-2020 start to incent development in non-core areas in the WCSB, starting to bring in areas outside of just the Montney and Duvernay in our production outlook,” he says.
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OUTLOOK
Crude oil forecast* Year
WTI crude oil 1 US$/bbl
Brent crude oil 2 US$/bbl
Edmonton light crude oil 3 C$/bbl
Alberta Bow River Hardisty crude oil 4 C$/bbl
Western Canadian Select crude oil 5 C$/bbl
Alberta heavy crude oil 6 C$/bbl
Sask. Cromer medium crude oil 7 C$/bbl
Edmonton cond. & natural gas C$/bbl
Edmonton propane C$/bbl
Edmonton butanes C$/bbl
Edmonton NGL mix 8 C$/bbl
2013 (9 mos.)
98.15
108.45
95.35
78.55
77.30
66.20
90.15
107.70
33.00
68.50
60.90
Inflation %
C$ to US$ exchange rate
2.0
0.980
Forecast 2013 (3 mos.) 2014
100.00
107.50
98.00
82.30
80.90
71.50
92.10
108.00
41.90
71.80
65.60
2.0
1.000
95.00
102.50
94.00
79.00
77.60
68.60
88.40
99.00
41.30
75.70
64.90
2.0
1.000
2015
94.40
102.10
93.40
78.50
77.10
68.20
87.80
96.50
45.80
75.30
66.30
2.0
1.000
2016
93.60
98.80
92.60
77.80
76.40
67.60
87.00
95.70
48.10
74.60
66.90
2.0
1.000
2017
95.50
98.20
94.40
79.30
77.90
68.90
88.70
97.60
49.80
76.10
68.60
2.0
1.000
1 West Texas Intermediate at Cushing, Okla., 40 degrees API, 0.5% sulphur. 2 North Sea Brent blend 37 degrees API, 1.0% sulphur. 3 Edmonton light sweet 40 degrees API, 0.3% sulphur. 4 Bow River at Hardisty, Alta. (heavy stream). 5 Western Canadian Select at Hardisty, Alta. 6 Heavy crude oil 12 degrees API at Hardisty, Alta. (after deduction of blending costs to reach pipeline quality). 7 Midale Cromer crude oil 29 degrees API, 2.0% sulphur. 8 NGL mix based on 45% propane, 35% butane and 20% natural gas. *As of October 2013.
Source: McDaniel & Associates Consultants Ltd.
However, FirstEnergy is optimistic the differentials will soon narrow. King contrasts the current situation with last December, January and February, when the price gap between Canadian bitumen and WTI widened to as much as $40 per barrel. “There are some good reasons out there to think it will narrow more quickly from the current levels than what we saw last year,” he says, referring to increased options for moving crude, particularly by rail. Also, BP p.l.c.’s refinery at Whiting, Ind.—with a capacity of roughly 400,000 barrels per day—will switch to a diet of only Canadian heavy crude in November or December. Other factors he cites are maintenance outages at some upgraders, refineries and pipelines that will soon be completed. King says a key difference is that overall crude inventories in the United States are lower now than a year ago. Another difference is there are now more options for shipping crude out of the North Dakota Bakken. Also, he notes several pipeline expansions or reversals are in the works. They range from the Flanagan South project to Cushing, Okla., which is slated to come on stream in the second quarter, to Enbridge Inc.’s Line 9 reversal to move western Canadian crude to Ontario and Quebec refineries. Wood Mackenzie Limited expects Canadian producers to face price volatility for the remainder of the decade as export capacity remains tight and production continues climbing in the U.S. Bakken. “While temporary pipeline issues have recently eased the sharp decline of Canadian crude prices, we expect prices to remain volatile for the rest of the decade,” explains Mark Oberstoetter, upstream research analyst for Wood Mackenzie. Wood Mackenzie’s report, Volatile Canadian Crude Oil Prices—A Growing Challenge, notes that prices will remain volatile because certain Canadian oilsands projects remain attractive even with current weak bitumen prices. While the timing and progression of proposed infrastructure projects needed to alleviate export constraints is highly uncertain, the supply growth from both the oilsands and the Bakken play is comparatively firm. By 2015, Wood Mackenzie forecasts that non-upgraded bitumen production will grow by 540,000 barrels per day and, of this, 72 per cent will be from sanctioned projects that break even below US$60 per barrel. Much of the remaining growth comes from the ramp-up of existing projects already in production. Of the 37 future
projects or phases included in Wood Mackenzie’s oilsands outlook, 29 break even at a WTI price of below US$60 per barrel using a January 2013 discount date. Most of these projects are already sanctioned and have incurred significant sunk costs. “What our analysis shows is that point-forward economics for the vast majority of oilsands projects planned to start up between now and 2015 are attractive,” says Oberstoetter. If the assumed bitumen differential were to widen from 40 to 50 per cent of WTI, Wood Mackenzie says a larger number of projects would become marginal. Even so, 26 projects would retain WTI breakevens below US$70 per barrel under this scenario—the majority of growth would still be supported by healthy point-forward economics. “In short, inadequate market access results in a supply glut even under a more depressed bitumen price outlook,” adds Oberstoetter. “The Bakken is also booming, and we expect production to nearly double to 1.3 million barrels a day in 2015. This outlook is supported by robust economics, as the Parshall and Sanish fields—the most productive areas in the Bakken—break even at below US$50 per barrel.” The construction of new infrastructure projects could potentially alleviate constraints on the system, securing firmer pricing for Canadian and North Dakota crudes. However, many of these projects are at an early stage and significant challenges, both operationally and politically, lie ahead. The report indicates proposed projects such as Keystone XL and Northern Gateway could circumvent this bottleneck, but each project has its own unique challenges. “U.S. approval of the Keystone XL northern leg is still pending, and a continued delay will result in Keystone XL’s southern leg acting as a clearing mechanism for light oil from Cushing until the northern leg is approved and constructed,” says Skip York, principal analyst in Wood Mackenzie’s Oils Research Team. Wood Mackenzie expects the northern leg will ultimately go forward. The approval decision remains politically charged, so the timing could slide. Wood Mackenzie doesn’t see material infrastructure relief until the start-up of projects like Southern Access and Pony Express in 2014. The companies without a natural hedge via an accessible downstream position are the most impacted and may seek out rail as an alternative option. “Canadian prices will remain highly susceptible to refinery and pipeline outages or interruptions. Even post-2014, we forecast a tight view as production from existing and sanctioned oilsands projects ramp up,” adds York.
OIL & GAS INQUIRER • DECEMBER 2013
45
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OUTLOOK
rat race Feature
Energy service companies overshoot demand, waiting for LNG exports before major new growth begins
By Darrell Stonehouse
Photo: Joey Podlubny
W
ith supply of oilfield equipment and services outstripping demand, 2013 was a year of running hard to stay in the same place for Canada’s service industry. Most major players in the sector expect markets to slowly improve throughout 2014 before rebounding as oil and gas producers gear up to export production overseas. The Petroleum Services Association of Canada (PSAC) is forecasting a total of 10,800 wells to be drilled across Canada for the coming year, a 1.5 per cent decrease compared to the expected final tally of 10,960 wells drilled for 2013. On a provincial basis for 2014, PSAC estimates 6,555 wells to be drilled in Alberta, representing a decrease of less than one per cent in the province compared to forecast 2013. Manitoba is expected to see a 7.7 per cent drop in activity with 480 wells, while in Saskatchewan drilling activity is expected to fall by 3.5 per cent, with an estimated 3,196 wells to be drilled in the year ahead. British Columbia, on the other hand, is expected to see 550 wells drilled, 2.2 per cent higher than 2013. PSAC is basing its 2014 forecast on an average natural gas price of C$3.50 per thousand cubic feet AECO and a crude oil price of US$95 per barrel West Texas Intermediate. “We are slightly optimistic about gas prices toward the end of 2014; however, we expect little change in next year’s drilling levels for gas,” says Mark Salkeld, PSAC’s president and chief executive officer. “But an even more significant factor affecting drilling activity across Canada is the widespread and growing use of technologies such as hydraulic fracturing and
horizontal drilling—technologies that were once considered advanced innovations. “Quite simply, large-scale use of these kinds of technologies is creating a trend to fewer wells overall. By maximizing our use of technology, industry can increase production from existing wells, access more and deeper zones, and restart production from wells that have been shut-in. This means we can maintain or even increase production while drilling fewer new wells. In fact, one well today can be the equivalent of two, three or more wells drilled just 10 years ago. That’s a game changer for our industry.” Given the nature of the wells being drilled, with longer horizontals, meterage is becoming a more important metric, Salkeld says. “Yes, with respect to meterage, it’s playing a very significant role in looking at overall activity,” he notes. “We are tracking meterage, and we’ve gained every year and will gain again this year by 500,000 metres in total.” Incoming PSAC chair John Gorman says that for the past couple of years, well counts in Canada have remained relatively stable. “Even though the number of wells is not increasing substantially year-over-year, the wells we’re drilling are longer and more complex,” he says. “Through technology, we’re able to maintain production with fewer wells, but production is only half the equation; we need to be able to market our resources to a broader audience. “Access to overseas customers is essential to the oil and gas industry here in Canada.”
OIL & GAS INQUIRER • DECEMBER 2013
47
OUTLOOK
Horizontal wells drilled (January to October) 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0
’03
’04
’05
’06
’07
’08
’09
’10
’11
’12
’13
Source: Daily Oil Bulletin
Drillers prepare for LNG exports Canadian drilling contractors are expecting 2014 to be much like last year, but are preparing for increased natural gas drilling in 2015 as producers prove up supplies for proposed liquefied natural gas (LNG) export facilities. In his third-quarter report to investors and analysts, Precision Drilling Corporation president and chief executive officer Kevin Neveu said he expects producers to at least maintain current spending in 2014. “We’re not hearing about producer budgets being pulled down in 2014,” said Neveu. “If anything, there might be a slight bias upwards. The pull on our tier one rigs looks pretty good, and that would be positive. If you think about winter 2014 being at least as good as winter 2013, that’s not unfair.” The tapering off in drilling that occurred in late 2012 is not happening this year, he said. Precision is currently negotiating drilling rig contracts with customers, “who are trying to guide us toward a softer winter so we don’t jack prices up too hard on them,” he said. “I would say the information we get from our customers at the front line right now is biased negatively. They’re trying to give us reasons not to raise the day rate.” Precision said Canadian drilling in the third quarter was restrained, as producers laboured under cash flow constraints and limited access to capital, thanks in part to low natural gas prices. At the same time, company executives said the interest created by the Duvernay natural gas liquids play and the prospects for drilling to underpin future LNG exports from Canada’s West Coast continue to strengthen. “We see significant long-term, stable upside driven by foreign investors and large, integrated customers pursuing long-term opportunities,” said Neveu. “We are in the final stages of negotiation for several new-build, Super Series rigs for mid-2014 delivery and are confident that further new-build and upgrade opportunities are present.” He called the political environment in Canada “very supportive in terms of seeking multiple paths to expand Canada’s energy export potential.” As for LNG-related drilling contracts, he said Precision is also negotiating to send “deep, high-capacity, pad-type drilling rigs to northwest Alberta or northeast British Columbia. Ultimately, these will be drilling for projects funded either by foreign direct investment or large, integrated E&P [exploration and production] companies.” 48
DECEMBER 2013 • OIL & GAS INQUIRER
In the Duvernay play, he estimated “less than a handful of rigs are currently drilling. The Montney is a lot more active right now, and there are about 25 Precision rigs drilling there, and a few more are available.” Trinidad Drilling Ltd. has similar expectations for 2014. “The winter drilling season in Canada is shaping up well with firm demand, in particular for deeper, high-performance equipment,” the company reported in the third quarter. “Interest in plays such as the Montney, Duvernay, Horn River and Liard Basin in western Canada is increasing as customers understand the drilling requirements needed to supply natural gas to their proposed LNG plants in British Columbia. Trinidad believes that this interest will turn into increased rig demand as these projects become more certain, with higher drilling activity and requests for new equipment over the coming years.” The company is already taking advantage of the LNG opportunity. In 2013, it was awarded a five-year contract for a new rig to work in the Liard Basin, drilling LNG-related wells. The rig will be one of Canada’s largest and most technically advanced rigs and is expected to be completed in the second half of 2014. Oversupply plagues fracking industry Canada’s pressure pumping players faced lower prices in 2013 as supply of fracking spreads outstripped demand. But like drillers, the pressure pumping industry is expecting things to improve as 2014 unfolds and LNG plans firm up. Trican Well Service Ltd. reports a 20 per cent average decrease in overall Canadian pricing in the third quarter of 2013 compared to the third quarter of 2012 due to oversupply in the marketplace. It expects demand to increase, but it will be a while before prices turn around. “Based on discussions with Canadian customers, demand for pressure pumping services in the fourth quarter will increase over 2012 levels, but decrease sequentially due to the normal December slowdown experienced in the industry,” the company reports. “Activity levels are expected to be supported by growth in the Duvernay, as well continued strong demand in the Montney, Cardium and Deep Basin plays.” Although the Canadian market remains very competitive, the company expects fourth-quarter Canadian pricing to remain stable compared to the third quarter of 2013. Trican does not expect Canadian pricing to increase until activity levels and equipment utilization remain strong over a sustained period of time. At the present time, the Canadian market remains slightly over supplied to balanced with fracturing equipment, the company says. Trican expects 2014 fracturing demand to increase compared to 2013. In addition, it believes there will be more investment in the Duvernay play. Some producers like Encana Corporation and Chevron Corporation have announced positive results in the Duvernay lately, but there’s no further clarity on activity levels there, says Dale Dusterhoft, chief executive officer of Trican. “Our customers are still finalizing their work programs in there,” he says. “We anticipate that we’ll maintain our share in there, and so it’s still going to be a pretty strong contributor to Trican in 2014. It’ll probably start out relatively slow, but slow meaning similar to what we see now, and then grow throughout the year, so it’ll be a little bit more back-half weighted.” Trican anticipates that there will also be some level of LNGrelated drilling next year, but the majority of LNG-related drilling will occur past 2014.
OUTLOOK
WCSB frac sizes by play
Natural gas plays
Crew size (HP)
Fracs per well
Stage size (tonnes)
Horn River
40,000–50,000
20–25
150–300
Deep Basin
12,000–25,000
10–15
80–200
Montney
15,000–30,000
10–15
100–200
Duvernay
30,000–40,000
10–20
100–200
Crew size (HP)
Fracs per well
Stage size (tonnes)
Cardium
8,000–25,000
15–25
20–30
Alberta Bakken
4,000–15,000
12–20
20–30
6,000–9,000
12–16
20–40
20,000–30,000
10–20
4,000–6,000
15–20
Oil plays
Viking Beaverhill Lake Bakken
75–150
cubic metres*
6-12
*Beaverhill Lake acid frac Source: Calfrac Well Services Ltd.
Calfrac Well Services Ltd. is also cautiously optimistic for 2014, Doug Ramsay, chief executive officer, reported to shareholders in November. “Fracturing and coiled tubing activity in western Canada is expected to be strong over the long term with the development of liquids-rich gas plays, such as the Duvernay and Deep Basin, and
the movement towards liquefied natural gas export capability being the primary drivers of higher-anticipated future demand for the company’s services,” Ramsay reported. “Calfrac expects equipment utilization to increase in the remainder of the fourth quarter, with further improvement projected for the first quarter of 2014.” The company predicts that oil-focused activity will remain stable for the rest of the year with the introduction of higher-rate treatments in certain plays, such as the Cardium, driving higher equipment utilization. “The company has a strong and active customer base, as well as a number of long-term relationships with large customers in the Deep Basin and Duvernay plays,” said Ramsay. “Calfrac expects that well completion activity will continue to grow in Canada as many of these plays transition from delineation to development.” Recent results from both of these plays provide significant optimism about their future development. The Duvernay play, in particular, represents one of the most capital-intensive formations in western Canada and has the potential to materially increase the demand for completion services in that region over the longer term, said Ramsay. In addition to the liquids-rich gas plays, another driver of anticipated long-term growth is the emergence of LNG export opportunities, which is expected to increase with the influx of capital from foreign entities and large multinational companies, said Ramsay. Calfrac has entered into a multi-year minimum commitment contract for the provision of three fracturing spreads to Progress Energy Canada Ltd. for its Montney project in northeastern British Columbia. It is also active in the Montney and Horn River.
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OIL & GAS INQUIRER • DECEMBER 2013
49
OUTLOOK
A
mix of existing pipeline expansions and repurposing projects, combined with an explosion in transportation by rail, filled in some of the gaps in North America’s oil transportation network in 2013, helping to moderate price discounts between North American and world markets and, more importantly for Canadian producers, the differential between heavy and light crudes. But while these stopgap measures are welcomed by the industry, they aren’t a long-term solution, says Trisha Curtis, director of upstream and midstream research at the Energy Policy Research Foundation, Inc. New pipelines to new markets are needed and quickly, she says. “With all this crude oil, unless we can build some new largescale greenfield projects, we’re going to have logistical challenges,” Curtis, the lead author of the foundation’s recent report entitled Pipelines, Trains and Trucks: Moving Rising North American Oil Production to Market, says. “We have a lot of projects coming online, but a lot of them are on existing routes and they’re either expansions or retrofitting lines.” Curtis says the pipeline projects currently under development do not necessarily consider how to get Canadian or North Dakota crude to the east or west coasts of North America for export, and by not providing greenfield projects, there is a negative impact on the industry, and it is stalling an energy renaissance across North America. “To really capture a lot of the value of this renaissance, we have to move ahead with permitting and getting this stuff to move forward. In a high oil price environment, these price discounts matter, but producers are still producing. However, in a lowerprice environment, when you have these sizable discounts, it could hurt production,” she says. Since 2008, Curtis says, Canadian and U.S. crude oil production has increased substantially, but the old system of moving crude oil in North America has not adapted at a similar rate. “We have constraints on both the regulatory side and the commercial side for moving this crude oil. We have to realize that we had a system that historically moved crude oil from the Gulf Coast—we moved crude to the Gulf and then sent it up into the country. Now we are producing crude oil in North Dakota and Canada and we’re moving it south, and while these midstream companies have done very well and worked really hard dealing with this, we have not on a large scale—especially on the regulatory side—allowed the system to really change and adapt to move this crude out to processing centres.” Late in 2013, it appears efforts to access new markets for Canadian production are slowly moving forward. In early November, B.C. Premier Christy Clark and her Alberta counterpart Alison Redford announced they had reached a framework agreement to satisfy British Columbia’s five conditions on moving Alberta’s energy resources to new markets. “Today, we can report that we have reached an agreement between our two provinces on two important matters—Alberta has reached a broader understanding and acceptance of British Columbia’s five conditions, and our province has agreed to join the Canadian Energy Strategy discussions started by Premier Redford,” Clark said. The B.C. premier emphasized that while the fifth of her five conditions did stress a need for economic benefit to her province from any pipeline project moving Alberta crude to tidewater, Alberta’s royalties and taxes would not be part of negotiations.
Canadian existing and proposed oil export pipeline capacity Pipeline
Capacity (thousand bbls/d)
Target in-service
Enbridge Mainline
2,500
Operating since 1950
Enbridge Alberta Clipper Expansion
+120
Q3 2014
Enbridge Alberta Clipper Expansion
+230
Q1 2016
Kinder Morgan Trans Mountain
300
Operating since 1953
Trans Mountain Expansion
+590
Q4 2017
Spectra Express
280
Operating since 1997
TransCanada Keystone
591
Operating since 2010
TransCanada Keystone XL
+830
2015
Enbridge Northern Gateway
+525
Q4 2017
+525 – 850
Q4 2017
TransCanada Energy East
Total existing capacity Total proposed capacity
3,671 +2,820–3,145
Source: Canadian Association of Petroleum Producers
“When it comes to royalties, British Columbia has an interest in ensuring the provinces protect their royalties because we also receive really substantial royalties from our natural gas industry,” she said. “I think it was really important that before we agreed to the five conditions that we had complete clarity on what the province of British Columbia meant by those five conditions, and there was no doubt that the fifth condition was the real preoccupation for Alberta,” Redford said. Clark said there are many ways that British Columbia could enjoy economic benefits from a pipeline moving Alberta crude to the Pacific Coast that do not involve royalties or taxes from the neighbouring province. For example, she noted the potential for a new oil refinery in her province that could bring thousands of jobs. “The working group needs to figure out what those possibilities could be, and I know that they will be speaking to industry at the same time they are doing that. Obviously, they need to be a part of that discussion.” Without the two provinces reaching the framework agreement as they did in November, Clark said it would have been very difficult for further discussions to occur on the subject of getting Alberta crude to new markets via the West Coast. Clark noted that the five conditions her province set out for consideration of new pipeline projects were intended in part to address the social licence issues surrounding pipeline projects, addressing a lot of the concerns many B.C. residents have toward such pipeline projects. “There are people who are going to be opposed to anything, and we will always find that. But I got elected on a platform of economic develop ment, and people voted for me with a very clear mandate to develop our resource sector in British Columbia, and that is what I am doing.” OIL & GAS INQUIRER • DECEMBER 2013
51
OUTLOOK
The agreement between the provinces matters, but ultimately it will be the federal government that grants the approval for the two proposals to move Alberta oil to the coast and onward to Asian markets. Still, Enbridge Inc. president and chief executive officer Al Monaco told analysts in his third-quarter conference call that the agreement is cause for optimism. Enbridge has been working on its $6-billion Northern Gateway Project designed to deliver 525,000 barrels per day to the West Coast since 2004. “We think the announcement is quite positive that we’re seeing some good collaboration between the provinces,” Monaco said. “I think it shows leadership by both of the premiers and certainly what I take away and what we take away as a company is that this is a very good pathway, I think, to getting to a yes answer here, and I think it’s an excellent development. We have been confident for a while in where Gateway is going to head and that the project will move forward. “We’re leaving a lot of money on the table today,” he added. “You just have to look at where WCS [Western Canadian Select] trades relative to other benchmarks for heavy. So it’s critical that we get to those markets. We’ve got tremendous resources in Canada, and we are an export-based economy, so we do need access to the Asian markets, which are clearly the growth market going forward.” The agreement is also good news for Kinder Morgan Canada Inc.’s proposed Trans Mountain Pipeline expansion for the line that currently runs from Edmonton to Burnaby, B.C. The proposed expansion, if approved, would create a twinned pipeline that would increase the nominal capacity of the system from 300,000 barrels per day to 890,000 barrels per day. While Enbridge and Kinder Morgan look west to reach markets, TransCanada Corporation remains stalled in its efforts to move the Keystone XL Pipeline to the U.S. Gulf Coast forward. In August, it announced it was moving ahead with its plan for the Energy East Pipeline, a 1.1-million-barrel-per-day project to transport crude oil from western Canada to eastern 52
DECEMBER 2013 • OIL & GAS INQUIRER
refi neries and export terminals. The project is estimated to cost approximately $12 billion. Subject to regulatory approvals, it is anticipated to be in service by late 2017 for deliveries in Quebec and 2018 for deliveries in New Brunswick. TransCanada intends to fi le the necessary regulatory applications for approvals to construct and operate the pipeline project and terminal facilities in the fi rst half of 2014. A recent survey by Ipsos Reid shows major public support for the Energy East project. The survey found 75 per cent of Canadians agree Canada should use domestic oil before using oil from foreign sources, and Canadians surveyed overwhelmingly support pipelines that will serve Canadian markets, with 80 per cent in favour of moving oilsands crude from western to eastern Canada. “Increasing supplies of Canadian crude to eastern Canadian markets will benefit refiners, producers and consumers in their everyday lives,” David Collyer, president of the Canadian Association of Petroleum Producers (CAPP), says. “More domestic oil production means more economic growth and jobs for Canadians from coast to coast.” The online poll of 2,070 Canadians was conducted from Oct. 17 to 22, 2013, on behalf of CAPP. The poll is accurate to within 2.5 percentage points. Today, eastern Canada imports about 700,000 barrels of oil per day from foreign sources, out of the 800,000 barrels of oil per day consumed. These imports, from sources including the North Sea and Africa, are largely due to a lack of pipeline infrastructure to connect western Canadian producers to eastern Canadian refiners. A majority of Canadians also support West Coast pipelines as well, says the survey. Two-thirds of Canadians are in favour of pipelines to the West Coast to serve international shipping ports. The poll also indicates that 70 per cent of respondents agree it is important for Canada to access new markets for oil to reduce the reliance on exports to the United States, currently Canada’s only crude oil customer.
Photo: Kinder Morgan Canada Inc.
Work on the Trans Mountain Pipeline. Kinder Morgan wants to expand the line to carry 890,000 barrels per day of crude to the west coast.
The latest regional business news
Business
Intelligence Structured joint ventures offer an alternative to equity markets By Elsie Ross
With continued tight access to equity in the oil and gas sector, exploration
of capital to fully develop them, but it did not want to raise equity, “given the
and production companies are likely to be more willing to consider joint ven-
fact that at the time the stock price was in their view unappreciated,” said
tures to help co-fund their drilling, the Dealmakers Expo heard in October
Hiddleston.
in Calgary.
In discussions, Bellatrix did not want Graft on to be earning into exist-
However, that joint-venture partner doesn’t necessarily have to be
ing production through the joint venture while Grafton wanted to be drill-
another exploration and production company, but could be a financial insti-
ing lower-risk drilling locations, he said. The investment manager liked the
tution, Craig Hiddleston, managing director of structured products for
company’s Falher/Notikewin and Cardium prospects and wanted a program
Calgary-based Grafton Asset Management Inc., said in a panel discussion at
tailored around both of those formations. “We were seeking an appropriate
the event sponsored by PLS Inc.
risk-adjusted return and we wanted to make a commitment in the order of
“Our approach would be very similar to, but in certain instances a litt le
$200 million for drilling.”
different than, what a traditional farm-in deal would look like,” he said. For
Since the deal was first announced, Bellatrix’s share price has risen by
example, because the company is primarily driven to achieve a financial
more than 50 per cent, said Hiddleston. The stock has responded so well
return, it doesn’t care about items such as operatorship or sharing or trad-
because Grafton was able to show a dramatic improvement in the producer’s
ing information. “We are really there to co-fund drilling with the appropriate
capital efficiencies and recycle ratios, he suggested. “They were able to fund
risk profile and get our acceptable return,” said Hiddleston.
growth without dilutive equity and have better metrics.”
“Our overriding strategy is to create long-term partnerships with
Grafton’s approach to joint ventures is not a template other than it wants
best-in-class management teams and operating teams to be a repeat-
to find companies that are recognized as great operators, said Hiddleston.
able and meaningful component of a company’s ability to go drill and
“Whereas we leave them in the position of being the operator, we want to be
fund a drilling program.”
able to take comfort in the fact that they will be able to execute.”
Earlier this year, Graft on did a structured joint venture with Bellatrix
One way in which Grafton’s joint ventures are different from more traditional
Exploration Ltd., contributing $100 million toward a $122-million program
joint ventures is the stage of play development at which it gets involved. In
to drill 29 Notikewin/Falher and Cardium wells in the Willesden Green and
a normal joint-venture transaction, a joint-venture party is asked to “wear”
Brazeau areas of west-central Alberta. In September, Bellatrix said Grafton
some of the exploration risk and help figure out the play for a company, said
would boost its stake in the venture to $200 million. The total cost of the
Hiddleston. “What we would prefer to do is enter into a joint venture with a
joint venture, consisting of a 58-well, Notikewin/Falher and Cardium pro-
company once they have already been able to delineate the play better, have
gram, is expected to reach $244 million.
drilled enough wells to be able to understand with more predictable spaces
There were elements within the transaction that were unique to Bellatrix,
how the capital costs should come in, and [have] better predictability on how
and as Grafton has talked to other companies, they have other priorities that
productive the wells should be so that our entry point is at a lower level of
it also has been able to accommodate in a variety of ways, he said. “We think
risk than in a normal joint venture.”
that approach is applicable to many other companies in western Canada.” In the Bellatrix deal, the working interest was convertible into a gross overriding royalty (GOR) at Grafton’s option.
That lower level of risk, he said, should translate into Grafton being able to offer more att ractive terms to oil and gas companies. The investment manager’s criteria for selecting joint ventures is driven
“Some companies fi nd gross overriding royalties particularly unpalat-
by the joint venture’s ability to deploy a meaningful amount of capital in
able,” said Hiddleston. “In the case of Bellatrix, they didn’t find that as prob-
a low-risk way, achieving appropriate returns for that risk, according to
lematic as some others might; as a consequence of that, our investors have
Hiddleston. Fundamentally, this is driven by management teams as Grafton
appreciated the fact that there is a lower risk profile to having a GOR and we
doesn’t want to operate a project.
were able to offer better terms in return to Bellatrix.”
The company likes to fund between $50 million and $500 million per com-
He said that Grafton wanted to partner with Bellatrix because “they
pany, which could take between one and two years. An important part of
are [a] great company” that has grown its production to 20,000 barrels of
that is having a statistically significant number of wells to be funded. “We
oil equivalent per day, all through the drill bit, “which is very difficult on its
don’t want to be in a program where the wells are $10 million per [program]
own.” The company had identified 1,700 drilling locations requiring $8 billion
and you have one or two bad wells and totally destroy a drilling program.” OIL & GAS INQUIRER • DECEMBER 2013
53
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