Canada Shale – Explaining the challenges in the low commodity environment

April 22, 2016

Author: Sona Mlada, Senior Analyst

Publisher: Oil & Gas Financial Journal

Canada is the fifth largest producer of hydrocarbons in the world (after the United States, Russia,
Saudi Arabia and Iran); 2016 average annual production is expected to be over 7 million barrels of oil
equivalent per day (oil & gas combined). Almost 60% of this production is represented by light oil. In
fact, Canada is the fourth largest light oil resource holder (after Russia, Saudi Arabia and the U.S.),
with over 130 billion barrels of remaining economical resources, almost 80% of which are represented
by the oil sands. Shale production in Canada has become an important source since 2010. Due to the
depth and geology structure, the shale formations in Canada are on average much more gas‐prone
than in the U.S. In 2016, nearly 80% of the shale production in Canada will be represented by rich gas
(in the U.S. this is ~65%). As Figure 1 indicates, the conventional production in Canada has been on a
steady decline since 2007. Historically, oil sands were the fastest growing supply source. Growing
supply from oil sands helped the country to maintain its overall annual production flat – and if it were
not for shale, production in Canada had never experienced a growing trend in 2010‐2014 (average
growth of 4% p.a.). The following article will provide an overview of the shale plays in Canada,
explaining the challenges faced in the low commodity price environment.

Geology of the Canadian Shale

Western Canada represents a treasure for Canada in terms of unconventional plays. Historically, the
area of Western Alberta has been submerged during several geological ages. During the Devonian
age, the sediments of Horn River Shale (Middle Devonian) and Duvernay Shale (Late Devonian) were
deposited, followed by the Mississippian age, which contributed to the deposition of the Alberta
Bakken Play (younger Banff and Exshaw formations are Mississippian age, underlying Big Valley is
late Devonian). The two younger formations are Montney Play deposited in Middle Triassic and
Cardium Play (Cretaceous). While Horn River and Duvernay are pure shale plays, Alberta Bakken is a
mix of shale and tight sediments, Cardium is comprised primarily of sandstones and Montney is a
hybrid of conventional formations, tight sands and black shale. The structure of the formations is
especially complicated in the area of Foothills in the province of Alberta, where Duvernay, Montney
and Cardium form a stacked potential, with Duvernay depth ranging from 3,000m to 4,500m; the
depth of Montney ranges from 2,000m to 3,300m and Cardium from 1,000m to 2,500m. All three
formations get deeper towards the Rocky Mountains on the border between Alberta and British
Columbia (refer to Figure 2).

 

Recent development in horizontal rigs
Horizontal rigs in Canada experience a strong seasonality effect, as Figure 3 suggests. The number of
rigs bottoms twice a year – in May (weather seasonality), when the soil gets muddy and it becomes
more difficult to operate the rigs, and in December just before year‐end. The number of horizontal
rigs in Canada reached its peak in February 2014, when 451 rigs were running in the provinces of
British Colombia and Alberta. After the commodity prices collapsed in late 2014, the February 2015
number reached just above 300 rigs (a 33% decrease Y‐o‐Y). As of now (February 2016), there are
only ~180 horizontal rigs in Canada, representing a further decrease of 40% Y‐o‐Y.

Largest acquisitions in the Canadian Shale

The M&A market in Canada cooled down in 2015 – the total value of all upstream deals in Canada
amounted to only ~$10 billion last year. Out of all acquisitions in Canada since 2010, the five largest
have all partially or completely been related to shale acreages and shale‐focused companies. The
three largest shale acquisitions in Canada occurred in 2012. The first one announced in June 2012
was the bid of Malaysian Petronas to acquire Progress Energy Resources for $5.3 billion, followed by
a bid of CNOOC to acquire Nexen for $15.1 billion announced in July 2012. Both included vast
acreage positions in Montney Shale and Horn River Shale. (Nexen held 300,000 acres in the shale gas
area of the northwestern British Columbia in the Liard Basin, Cordova Basin and Horn River Basin and
Progress Energy held 139,150 acres in the Montney Shale). Both bids were evaluated to determine
whether they would be of net benefit to Canada. The third largest acquisition was ExxonMobil
acquiring Celtic Exploration for $3.15 billion, including 104,000 net acres in the Duvernay Shale and
545,000 acres in Montney Shale.


LNG in Canada and its future
Many of the above‐mentioned acquisitions happened with the intention of operators to invest into
building LNG export terminals on the Western coast of British Columbia. Particularly in the years
2012 and 2013, when the LNG landed price oscillated around 12 $/kcf in the East Asian LNG spots,
shipments of the liquefied gas from Canada seemed like a top‐notch investment. At that time, the
realized gas price in North America was on average four times lower compared to East Asian
markets. Multiple operators applied for a facility permit from the B.C. Oil and Gas Commission,
however, the first project in the province to receive the permit is Shell operated LNG Canada. The
joint venture partners in the facility are PetroChina, KoreaGas and Mitsubishi. Shell operates
~300,000 net acres in the Montney Play, located primarily in the Groundbirch and Gundy areas. In
addition, it holds over 350,000 acres in the Duvernay Shale. The LNG Canada Project, located at
Kitimat, has an expected facility of 3.23 Bcf/d. The project could cost nearly $40 billion, initially
consisting of two trains, with a potential expansion to four trains in the future. Since LNG prices
follow the oil prices, the LNG landed prices in East Asian markets have fallen to ~7 $/kcf. This is one
of the main drivers for the joint venture to postpone its final investment decision to the end of 2016.

Investments in the Canadian Shale
The upstream business in Canada was hit hard by the drop in commodity prices. In the country as a
whole, investments fell by ~40% Y‐o‐Y in 2015 and are expected to fall by a further 30% Y‐o‐Y in the
current year. The drop in shale investments is even more significant: ~45% in 2015 Y‐o‐Y and over
30% in the current year. However, shale investments are expected to recover faster in 2017
compared to other supply sources. The estimated increase of 2017 investment in shale is ~50% Y‐o‐Y.
As Figure 4 indicates, companies in Canada reduced shale investments across all company segments.
In real terms, total investments dropped by almost $3.5 billion in the Montney Play in 2015 and
~$1.5 billion in the Cardium Play. Investments in the largest Canadian play, Montney, will drop by a
further ~$1.5 billion in the current year.

The largest Shale Play in Canada – Montney
Montney is the largest play in Canada, both in terms of production and investments. In 2015, on
average, the play produced over 850 thousand barrels of oil equivalent per day, of which ~550
kboe/d were coming from the British Columbia part of the play. In British Columbia, the Montney
production is primarily represented by rich gas – only ~5% of the total production consists of light oil.
On the other hand, in Alberta, the operators tend to target liquid‐rich Montney, causing the average
light oil content to be slightly above 20%. The largest operators in the British Columbia part of the play are Encana, Petronas, Shell and Arc Resources (ordered by the 2015 production). As Figure 5
suggests, Encana is the operator with the highest number of stimulation stages (21) and the highest
volumes of proppant used (over 8,600 thousand lbs) for stimulating its Montney wells in British
Columbia, on average. Consequently, Encana is the operator with highest average 30‐day IP rates –
for the wells completed in 2014 and 2015 the realized 30‐day IP rate for the operator was 9
mmcfe/d, compared to 5.7 mmcf/d for Arc Resources, 3.6 mmcfe/d for Shell and 3.4 mmcfe/d for
Petronas.

About 40% of the total well cost for the Montney wells is represented by drilling; the remaining 60%

is completion cost. Over the last four years, the average well cost in the Montney Play has decreased
by over 12% p.a. This is partially driven by the cost compression realized by the operators in 2015
and 2016, as well as increased pad drilling and improved well completions. In 2015, over 90% of all
Montney wells in British Columbia were drilled using multiple wells pads.

Conclusion
In 2015, total gas production from Canada Shale reached 6.6 bcf/d. In 2016, the production is
expected to be flat Y‐o‐Y; however, only ~5.8 bcf/d is represented by wells that are currently
producing (as of February 25, 2016). Figure 6 indicates (in different shades of yellow) the break‐even
price of production from wells that have been spudded and are awaiting completion. The gas
production from Canadian shale has a potential to grow to above 11 bcf/d by 2020; however, almost
40% of this production is represented by wells with wedge breakeven prices above 3 $/kcf. The
current Henry Hub price oscillates around 1.9 $/kcf and the current AECO prices around 1.2 $/kcf.
Stronger gas prices will be crucial for the Canadian shale gas market to achieve a growth in the gas
supply post 2017.

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Article Contacts

Sona Mlada, Senior Analyst
Phone: +47 90 20 16 45
sona.mlada@rystadenergy.com

Julia Weiss, VP Marketing
Phone: +47 48 29 87 61
julia.weiss@rystadenergy.com

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