May 2015

ShaleTech: Canadian Shales

Drilling, LNG prospects face stiff headwinds
Jim Redden / Contributing Editor
One of the two, or three, rigs that Encana will run this year in its Duvernay leasehold. Courtesy of Encana Corp.
One of the two, or three, rigs that Encana will run this year in its Duvernay leasehold. Courtesy of Encana Corp.

Like the proverbial wet blanket, disquieting forecasts that have Canada’s unconventional sector devolving into a shadow of what it was only a few months ago, have effectively tempered the full-bore gushing that early last year accompanied the unveiling of the highly prospective Torquay shale play in southern Saskatchewan.

To be sure, the prevailing 2015 outlook across the 540,543-mi2 Western Canadian Sedimentary basin (WCSB) is perhaps best personified by Calgary’s Trilogy Energy Corp. “We’re taking two steps back and effectively not drilling, as we don’t think its profitable to drill in this environment,” Trilogy President and COO John Williams said during a First Energy Capital conference in March.

As of now, Trilogy plans to drill 10 net wells within its Kabob, Montney and Duvernay shale holdings, and likewise, has downgraded its 2015 production guidance to around 30,000 boed, from the 35,104 boed it averaged in 2014. Williams also told the Calgary Herald in January that the few wells Trilogy plans to drill this year will not be hooked up to sales lines anytime soon. “The wells we’re going to drill, we can drill and complete them, but we’re not going to produce them,” he said. “A third of our reserves come out in the first year. It doesn’t make sense to blow down the reserves into a low commodity price environment.”

According to an analysis by Norway’s Rystad Energy, Trilogy is certainly not alone, as many of the mostly homegrown independents that dominate Canada’s unconventional sector are deferring completions of newly constructed wells until prices stabilize. At the same time, new wells awaiting hook-up will be fewer and farther between, as aggregate drilling activity in the myriad liquid- and gas-rich shale plays of Alberta, British Columbia, Saskatchewan and Manitoba is expected to be cut nearly in half this year, Fig. 1.

Aerial extent of predominant shale plays in Western Canada. Source: National Energy Board.
Fig. 1. Aerial extent of predominant shale plays in Western Canada. Source: National Energy Board.

In a downward revision to its year-end 2014 forecast, the Canadian Association of Oilwell Drilling Contractors (CAODC) estimates a 41% drop in Western Canada’s rig count this year. The CAODC expects a 2015 average of 203 active rigs, compared to the 370 drilling in 2014. Historically, drilling picks up later in the year after the so-called “Spring break-up,” when melting snow and ice restrict the movement of rigs and equipment, but this is unlikely to be the case this year.

CAODC also predicts a total of 6,612 new wells to be drilled in Western Canada in 2015, about 57% of the 11,534 wells it estimates were completed in 2014. The Petroleum Services Association of Canada’s (PSAC) 2015 forecast was a bit more optimistic, with 7,650 new wells predicted this year. A Rystad Energy breakdown, meanwhile, shows some of Canada’s largest unconventional plays being particularly hard hit, with drilling in the Montney forecast to drop by around 35%, the Cardium by 45% and the nation’s premier tight oil play, the Alberta Duvernay, is expected to experience a roughly 30% decline.

At least, however, Rystad says wellhead breakeven prices for Canada’s tight oil provinces, relative to the West Texas Intermediate (WTI) pricing benchmark, are generally highly competitive with those of its southern neighbor, Fig. 2. The only glaring exception is the Duvernay, where in April Rystad found breakeven prices above the WTI benchmark, “reflecting the emerging nature of the play and high drilling costs.”

Weighted wellhead break-even price comparison of key Canadian and U.S. tight oil plays.  Source: Rystad Energy.
Fig. 2. Weighted wellhead break-even price comparison of key Canadian and U.S. tight oil plays. Source: Rystad Energy.

Moreover, despite the long-term investment horizons of the prolific Alberta oil sands–largely responsible for making Canada the world’s fifth-largest oil producer, the International Energy Agency (IEA) in January predicted production of both light and heavy crude at around 4.3 MMbpd in 2015, which represents a year-over-year increase, but falls some 95,000 bpd short of its December forecast.

As for gas, the National Energy Board (NEB) shows average monthly marketable production of around 417,000 Mcmd in 2014, a 13.5% increase over the 2013 monthly average of approximately 367,449 Mcmd. With nearly all gas production concentrated in the provinces of Alberta and British Columbia, Callan McMahon, Wood Mackenzie’s principal analyst for North American Upstream Research, told World Oil’s inaugural Shale Tech Canada conference on April 21 that cumulative gas production from the Montney, Duvernay and Deep basin is expected to add 1.4 Bcfd and 1.0 Bcfd in 2015 and 2016, respectively.

Over the longer term, Canadian gas producers continue to hold out hope that a host of planned LNG export facilities in various stages of development in British Columbia (B.C.) will become reality. However, given current economics and stiff competition from brownfield facilities in the U.S. Gulf Coast, a giant question mark hangs over the LNG prospects.


For a handful of operators, led by Calgary-based Crescent Point Energy, comparatively low breakeven costs have made the Saskatchewan and Manitoba extension of the Bakken shale a viable antidote to declining commodity prices. The North Dakota link was reinforced further, early last year, when operators began falling over themselves to snatch up acreage in southern Saskatchewan, prospective for the emerging Torquay shale. It is the Canadian equivalent of the lower Three Forks, where players quickly reported quick payouts, with well costs as low as $3.5 million.

Canadian Bakken pioneer Crescent Point holds more than 220 net sections prospective for the Torquay, which it augmented with the May 2014 acquisition of privately held CanEra Energy. After drilling 36 wells in its core Flat Lake acreage near the U.S. border, with net production of 5,100 boed, President and CEO Scott Saxberg last year put the Torquay on the same scale as the flagship Viewfield-Bakken play, which produced just over 63,000 boed last year. “These are low-decline, high-rate-of-return wells that pay out in less than seven months,” he said at the time.

A year later, and with oil prices at nearly half of their 2014 peak causing a wholesale pull-back across onshore Canada, Crescent Point has laid out a surprisingly aggressive drilling program, telling investors in April that it has budgeted for at least 617 new wells in 2015. Canada’s most active horizontal driller says C$1 billion of its reduced 2015 capital budget of C$1.45 billion is earmarked for Saskatchewan. “We will review the budget again after spring breakup, to determine allocation plans that best position us for 2016,” Saxberg told analysts last month.

Meanwhile, Crescent Point credits a two-year-old waterflood program, and the recent transition to NCS Multistage Unlimited’s closable casing sleeve frac system, with helping to wring more oil economically out of its premier Viewfield-Bakken leasehold. Since initiating the program, the operator says it has generated a 4% recovery factor, and a 26% increase, in proved and probable recoverable reserves.

“If we have 25 fracs in one wellbore, we could go in very easily with a coiled tubing unit and close off five or six sleeves, and divert water from the injector to different parts of the offsetting wells,” Saxberg explained. 

Vermilion Energy also entered the Torquay play in April 2014 via its 72,000-net-acre acquisition of privately-held Elkhorn Resources. Unlike Crescent Point, however, Vermilion primarily targets the Mississippian Midale in Saskatchewan and Manitoba, with the Bakken-Torquay a secondary horizontal objective. Drilling in both plays will be limited this year, says CEO Lorenzo Donadeo.

“Our Saskatchewan land base has limited expiries, allowing us to reduce drilling activity on these assets to five wells in 2015. For 2015, our Canadian operational plans reflect a significant reduction in activity levels, as we seek to preserve our financial flexibility and balance sheet strength,” he told analysts.

Legacy Oil+Gas, which has a significant light oil leasehold in southeastern Saskatchewan and southwestern Alberta, likewise concentrates on the Mississippian Midale in its Pinto and Steelman area horizontal program. For the time being, the Torquay has been put on the back burner, CEO Trent Yanko told investors on March 26.

“We still remain very interested in the Three Forks (Torquay) and in its potential, particularly in our Taylorton Pinto area, where we have probably north of 60 net sections in that play. Unfortunately, one of the items that is not in the budget right now is any step-out or call it exploration-style drilling. But, we do hold the majority of the lands by production, so the opportunity is not going anywhere for us.”

Legacy participated in 159 gross wells last year, after drilling only 10 wells in the fourth quarter as it began “tuning our capital budget into the reduced oil price environment,” Yanko said. After a 55% reduction in spending for 2015, the company plans to drill 72 gross wells, mainly targeting the Midale.


Alberta’s liquids-rich Duvernay, a conglomeration of interbedded bituminous shales, calcareous shales and dense argillaceous limestones extending beneath the Peace River Arch and Calgary, remains Canada’s premier tight oil play. However, given its deep, over-pressured and complex geological make-up, it also ranks as one of the most expensive to drill and complete, putting it squarely behind an eight ball in today’s economic climate. Consequently, as Encana President and CEO Doug Suttles emphasized to investors in February, driving down total well costs is “priority du jour” in the still-developing play, that not so long ago required up to $20 million/well to drill and complete.

ConocoPhillips is targeting the stacked pay potential of mature and emerging unconventional formations in its widespread Alberta leasehold. Source: ConocoPhillips.
Fig. 3. ConocoPhillips is targeting the stacked pay potential of mature and emerging unconventional formations in its widespread Alberta leasehold. Source: ConocoPhillips.

“We targeted $15 million on our first multi-well pads, and we’re headed towards a long-term target of $12 million/well, and are actually getting pretty close to that already. So, the question is, how much lower can we go, because clearly we have got to set a new target now?” Suttles said.

Encana, which controls 343,000 net acres in the play, where it operates under a joint venture with PetroChina subsidiary Phoenix Energy Holdings, completed four multi-well pads last year and reduced its total per-well cost 38%, compared to 2014. The operator credits optimized wellbore designs, fit-for-purpose equipment and implementation of its resource play, hub development model for helping deliver some of its wells at a play-low cost of $12.4 million/well.

As of now, an estimated $230 million is allocated to the Duvernay, where Encana plans to average two to three rigs, and drill about 15 wells in the Kaybob and Simonette areas. Its 2015 Duvernay production guidance calls for 5,000-6,000 bpd of NGLs, 200-400 bcpd and 25-35 MMcfgd.

ConocoPhillips, which has staked much of its future resource growth on North American shale plays, holds over 3 million net acres in Alberta, where it has identified more than 6,000 ft of stacked pay, targeting a mixed bag comprising the mature Cardium and Glauconite horizons and the more emerging Duvernay, Montney and Falher/Wilrich plays, Fig. 3. “We get a good return from these plays, because a lot of them are drilled within existing infrastructure,” Matt Fox, executive V.P., Exploration and Production, said during the April 8 investor day. 

While providing no specifics on 2015 activity plans, Chairman and CEO Ryan Lance told analysts that Western Canada figures heavily in the company’s long-term prospects to grow its shale resource base. “In particular, it should grow over time. For example, in Western Canada, we’ve gone from five years ago, where we only drilled vertical wells through the reservoir and across that oil play, and today we only drill horizontal wells with multi-stage fracs. So, we’re still under the learning phase in Western Canada. That’s the place where I would expect to see some significant growth in the low-cost per supply base.”

An Athabasca Oil Corp. drilling location in Alberta’s Kabob sub-basin. Courtesy of Athabasca Oil Corp.
Fig. 4. An Athabasca Oil Corp. drilling location in Alberta’s Kabob sub-basin. Courtesy of Athabasca Oil Corp.

Like Trilogy Energy, Athabasca Oil Corp intends to defer completions on four recently drilled Duvernay wells, and postpone one planned drilling project, at least to the second half of 2015, Fig. 4. President and COO Rob Broen said if the wells are completed, as planned, in the second half, Athabasca would meet its 2015 light oil production target of 7,000-8,000 boed, which he said represents a 52% year-over-year increase.

Athabasca holds 200,000 acres within the liquids-rich Kaybob sub-basin, where it produced over 6,200 boed in the last six months of 2014. During the year, the company drilled and/or completed a cumulative 11 Duvernay horizontal wells.

Vermilion Energy, meanwhile, drilled only two Duvernay horizontal appraisal wells last year, but elsewhere in Alberta it drilled 25.9 net Cardium wells, including 17 with greater than 1-mi laterals, said CEO Donadeo. “We will monitor the performance of our two appraisal wells that we drilled in 2014, but have deferred further Duvernay drilling activities to beyond 2015,” he said.


Painted Pony Petroleum is quick to point out that its growth prospects are not tied directly to the export of LNG from British Columbia. While acknowledging that it is “ideally suited and situated to be a future West Coast LNG supplier,” the Calgary independent stresses its five-year plan “is based entirely on North American sales, with no reliance on LNG.”

Thus, the conundrum facing operators tied into the colossal dry gas citadel of the Montney, Horn River and northernmost Laird basin, which the British Columbian energy ministry has said collectively holds an estimated 2,933 Tcf of gas-in-place. Earlier projections that had copious exports of LNG slicing away bloated gas supplies, and raising prices, have been toned down appreciably, as final development decisions remain up in the air. At last count, Canada had some 22 LNG export facilities in various stages of development, with most either still in the planning phase, or awaiting a final investment decision (FID). Of those, 17 are planned for British Columbia, but as of now, only the WesPac LNG facility is scheduled to begin deliveries anytime soon. However, its projected 2016 start-up would come with a comparatively petite capacity of 3 MMpty, according to a Gas Processing roundup.

In the meantime, although gas production continues to rise, operators are keeping a tighter hold on their drilling dollars. The British Columbian Oil and Gas Commission recorded 163 new wells drilled in the first quarter of 2015, compared to 212 constructed between January and March of 2014. Throughout the WCSB, CAPP said a total of 2,145 gas wells were completed in British Columbia, Alberta and Saskatchewan in 2014, up significantly from the 1,624 new gas wells put online the year prior.

Painted Pony, for one, said it has reduced its 2015 capital budget by well over half, from $295 million in 2014 to $104 million this year. The company told investors that it plans to drill 14 net Montney horizontal wells in its Blair and Townsend holdings, of which 11 will be completed. Painted Pony exited 2014 with a 52% increase in average production to 79.2 MMcfed, and during the year also established a 15-year processing, marketing and transportation alliance with AltaGas.

As with the approach taken in its Duvernay operations, Encana has a joint venture in play through 2019 with Mitsubishi Corp. that covers 409,000 net acres in the dry gas, Montney Cutback Ridge area. For now, Encana plans to average three rigs in the Montney this year, while expanding its local gathering and processing facilities to exit 2015 with total capacity of 1,100 MMcfgd. 

Notwithstanding its name, Tourmaline Oil Corp. has emerged quietly as one of Canada’s premier gas producers, with extensive holdings in both the Montney of northeastern British Columbia, as well as Alberta’s Deep basin, where it now holds a commanding 1.35-million-acre position. In 2014, the Calgary-based operator produced, on average, between 200-225 MMcfgd from its Sunrise/Dawson development, where this year it plans to drill 30 Montney horizontal wells, and one targeting the Doig formation. To the east, Tourmaline closed on the acquisition of Perpetual Energy Inc. in March and its holdings in the Edson area of the Deep basin. 

Tourmaline, which reduced its year-over-year active rig count from 20 to 15 active units, plans to drill 40 fewer wells this year. 

Elsewhere, formerly entrenched Montney players Talisman Energy Inc. and Apache Corp. last year liquidated much of their dry gas holdings in the play, with the former being acquired officially by Repsol S.A. on Feb. 20. In December, Apache sold off its 50% stake in the Kitimat LNG plant, and the associated 644,000 gross acres it held in the Horn River and Liard basins, to Australia’s Woodside Petroleum Ltd.

The Apache pull-out represents the latest twist in the continually revolving ownership—and still uncertain future—of the Kitimat LNG project on Bish Cove. Now operated jointly by Chevron and Woodside, Kitimat remains in the Front End Engineering Design (FEED) phase, with no projected date to begin exporting up to 10 MMpta, according to Gas Processing.

Kitimat clearly exemplifies the ambiguities surrounding the LNG export picture in Canada, as facility owners must tangle with ever-increasing development costs, and equally growing volatility in the international market. There also is the matter of dealing with a spate of LNG export facilities proposed for the U.S., which, unlike Canada, largely involves less-expensive conversions from import to export, as well as contracts tied to the more competitive Henry Hub price benchmark, rather than indexed to oil.

What is clear, however, is that the proposed merger of Shell and the BG Group means at least one of two planned LNG plants will likely never reach fruition. Shell Canada is the lead operator on the LNG Canada facility proposed for the Kitimat area, while BG is the sole owner of the planned, Prince Ruppert LNG project on Ridney Island. For now, Shell is still onboard for a 2019 start-up, while Gas Processing lists the BG project as being “on hold.” 

Meanwhile, the CEDIGAZ international center for natural gas information admits that while greenfield British Columbian proposals have difficulty competing economically with brownfield U.S. terminals, time is of the essence in getting projects off the starting blocks. “If final investment decisions are not taken soon, the Canadian LNG industry’s take-off could be postponed 10 years or more, as LNG projects in the United States are moving forward quickly and could meet a significant share of the global demand,” CEDIGAZ concluded in its latest report, “Waiting for the Next Train? An Assessment of the Emerging LNG Industry in Canada.” 

“In that respect, 2015 will be a pivotal year for Canadian projects.” wo-box_blue.gif  

About the Authors
Jim Redden
Contributing Editor
Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.
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