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Canada: Stuck Between a Rock and a Hard Place

June 5, 2015 | By Warren Waite

In recent Get the Point postings PointLogic Energy has discussed in detail about the natural gas production boom in the lower 48, where the growth is occurring, the drivers behind that growth and what growth will look like going forward given the lower commodity price environment.

In this edition of Get the Point, our attention shifts to our neighbor to the north, Canada. Gas production in Canada has followed a similar trend in recent years as the U.S., however the timing and magnitude of the change isn’t necessarily one and the same. This issue will detail some of the resiliency of gas production in Canada. In part two, we’ll look at the displacement effect that growing U.S. production has had on Canada, the impact on prices, and much like the U.S., the big bets being made on the prospects of exporting Liquefied Natural Gas (LNG) to global markets.

Putting it into perspective

Dry gas production in Canada averaged 16.6 billion cubic feet per day (Bcf/d) in 2006 and fell 18 percent to reach 13.6 Bcf/d by 2012. Then as a result of the North American shale revolution, production began to rebound by 2013. Breakthroughs in drilling technologies and techniques were being applied not only in the U.S., but in Western Canada as well.

The Western Canada Sedimentary Basin (WCSB) accounts for about 99 percent of all production in Canada. Shale plays in the WCSB, were the central focus of the shift from years of decline to a time of growth. Plays such as the Montney in British Columbia (B.C.) and the Duvernay and Cardium in Alberta led the production charge. The WCSB spans from northeast B.C. to southwest Manitoba.

Western Canada Sedimentary Basin

Since 2013, dry gas production has grown 10 percent to average 15.1 Bcf/d year-to-date. Like the major shale basins in the U.S., the drillers tended to focus their attention not necessarily on natural gas, but on oil and natural gas liquids (NGLs) that provide a more attractive economic uplift. Thus, a large swath of the gas production growth in North America has been ‘associated’, or gas extracted from a targeted liquids-rich well.

Canada Dry Gas Production

On a percentage basis, gas production in Canada and the U.S. each grew 10 percent since 2013. However, production volume in the U.S. is nearly five times that of Canada. In fact the Northeast region of the U.S. produces more than Canada does as a whole. That milestone began Nov. 2013. The Northeast is now producing 18.8 Bcf/d, or 25 percent more than all of Canada. Texas production surpassed Canadian production in mid-2007 and is presently around 20 Bcf/d, or 34 percent greater than that of Canada.

Lower 48 Dry Gas Production

Fallout from the price plunge

West Texas Intermediate (WTI), the U.S. benchmark for crude oil prices, have fallen from near $105 per barrel (bbl) in June 2014 to near $60/bbl in recent weeks, a decline of 43 percent. Meanwhile, Western Canadian Select (WCS), the Canadian benchmark for crude, has fallen from $86/bbl to $49/bbl, a 43 percent decline over the same period (see rig and price graphs below). Naturally, producers and service companies have tightened their belts, pulled back on drilling activity and in some cases reduced their workforce in order to adapt to the reality of a lower hydrocarbon price environment.

According to the Canadian Association of Petroleum Producers (CAPP), capital investment in Western Canada, including the oil sands, is forecast to total $46 billion this year, down 33 percent from 2014. Naturally, with the drop in spending, industry unemployment rises. “Companies have announced more than 4,500 layoffs, with an additional 23,000 jobs lost as a result of lower drilling activity”, CAPP said in a May report.

Canada Between a Rock and a Hard Place

Market sentiment is that low oil prices may not be short lived and it could take a few years for the market to work itself out of an over-supply situation. So what is the average Canadian producer to do? Unfortunately, some tough times are likely still ahead. In many cases, material demand is at least a few years away if not more depending on your location in North America. In part two of this issue of Get the Point, we’ll discuss some avenues of future gas demand for Canada like LNG exports, gas consumption in the oil sands and gas-fired power generation. We’ll also take a look at the trend of declining gas exports to the U.S. and what that may look like in the future. Until then, it appears Canada is stuck between a rock and a hard place. Meaning the production of hydrocarbons, the associated jobs that come with that and the impact on the Canadian economy teeter on the fruition of infrastructure projects, LNG export projects, regulations, government policies and the overall price of natural gas, NGLs and crude.

Oil prices matter and this is especially noted in the correlation of activity for oil and gas rigs. The Baker Hughes monthly oil and gas rig count for the U.S., including Alaska has fallen 52 percent since June 2014 to average 889 in May. Over that period, gas directed rigs declined 29 percent to average 223 rigs in May while oil directed rigs plummeted 57 percent to average 662 in May. The last time the U.S. rig count was below 900 was in June 2009 when WTI averaged close to $70/bbl.  Baker Hughes data also suggest that horizontal drilled wells account for 77 percent of the U.S. rig count, a gain of 10 percentage points since June 2014. Horizontal drilling provides greater economies of scale than drilling a vertical well due improved access to the natural resource and lower supply costs.

Rig Count and Price of U.S. Crude

Similar to production, the amount of active rigs drilling in Canada are a fraction as what operates in the U.S. Nonetheless, the decline in rigs is dramatic. Overall Canada’s oil and gas rig count is now 80 a 66 percent drop, or a loss of 155 rigs since last June. It’s no surprise the overwhelming share of these have been oil focused rigs, which have declined 83 percent to average 24 rigs in May. Gas rigs currently stand at 56, a 41 percent decline since June 2014. Horizontal wells in Canada account for 95 percent of all drilling activity, a gain of five percent since last June.

What is different in the seasonality of rig counts between the U.S. and Canada is that drilling in Canada typically peaks in the winter then falls hard in the months of April, May and into June. This is referred to as the spring break-up as the frozen earth in the WCSB thaws turning dirt roads and drilling sites into a muddy mess. During this time roads can become impassable and producers simply have to wait it out. This year’s spring break-up sent the operating rig count into a free fall, falling by 77 percent since January. Though smaller in volume compared to previous years, this year is about five percentage points above the prior three-year average of how many rigs are typically laid down from January through April and May.

Rig Count and Price of Canadian Crude

Producers find a way

The effects of falling rig counts aren’t as detrimental to production as it used to be. There have been tremendous gains in drilling efficiency and productivity in the WCSB. Producers simply can do more with less. That’s why many producers have declared year-on-year production gains despite announcements of cuts in capital expenditures. Additionally, as service costs have come down, this has helped boost producers’ internal rate of return in conjunction with the improvements in drilling efficiency and productivity. In some cases, depending on the producer, the acreage they hold and their high-grading opportunities within select basins could be just as profitable in the current low price environment as they were one year ago.

Another developing trend is drilled but uncompleted wells (DUCs). This was touched on a few weeks ago in Gas Production at a Standstill?, posted May 21. The uncompleted well inventory in the U.S. is growing and is estimated to be over 2,000 according to industry sources. Producers are deferring the completions costs and letting the natural resource sit in ‘inventory’ until prices recover and economics improve. Well completions account for roughly 70-75 percent of the well cost, while drilling amounts to 20-25 percent. The vast majorities of the DUCs are in shale plays and have been dubbed as ‘fracklog’ – a backlog of U.S. shale wells that have yet to be hydraulically fractured and fitted for production.

Encana Corporation highlighted many of the aforementioned achievements producers are realizing in a 1Q 2015 investor presentation on May 12.  In Encana’s case they are driving value by gaining efficiency through innovation, drilling better wells at a lower cost, improving their flexibility in assets to respond to changing commodity prices and are finding creative ways to bolster liquidity and reduce debt. For fiscal year 2015, Encana stated that roughly 80 percent of their capital will focus on their highest margin and most strategic assets. Those are the Permian and Eagleford in Texas as well as the Duvernay and Montney in Alberta.

Of the top 20 operators in Northwest Alberta, PointLogic data suggests that in 2013 Encana ranked third by volume.  Looking at the Duvernay, Encana expects to grow net production for 2015 by approximately 10 Million Barrels of Oil Equivalent (MBOE) per day. In the first quarter of 2015, Encana reported a 25 percent reduction in completion costs and 45 percent decrease in drilling costs compared to the first quarter of 2014. Part of the D&C cost reductions are achieved through the use of their resource play hub (RPH) model. The RPH model applies simultaneous drilling and completions operations on multi-well pads to drive greater productivity and cost efficiencies. Through the optimization of well completions, and the application of high intensity hydraulic fracturing, Encana is increasing initial production rates and delivering stronger well performance.


For the Duvernay, Encana has been able to reduce the amount of time from the date a well is spud to the rig release date for a 20,000 foot well by approximately 20 days over the last three years.

Duvernay: Encana's Drill Time

Likewise, in the Montney, Encana stated that improved completion design is driving over 30 percent production improvement on new wells. To date, their fastest drilled well took 13 days at a lateral length of 6,560 feet, a 10 percent improvement from the 2014 average. Encana also realized a $1 million reduction in D&C costs in the first quarter compared to the 2014 average.

Total Canada dry gas production rates are currently averaging 15.0 Bcf/d, levels last seen in the 2008-2009 time frame. However, net gas exports to the U.S. are down considerably. Canadian net exports to the U.S. have averaged 6.14 Bcf/d year-to-date, a decline of about 1 Bcf/d from what exports to the U.S. were over the same period in 2008 and 2009. Fortunately, domestic demand for natural gas in Canada has increased over the last six to seven years to help absorb the shift in how gas is dispatched within and from Canada. In order for the market to balance going forward, will Canadian production need to decline or increase?

In part two, we’ll take a dive into the demand side of the equation and explore different demand components for gas consumption within Canada. Until significant gas demand arrives, Canadian producers will continue to feel the displacement and price pressure effects from the market and infrastructure changes taking place in the lower 48. How long will that be? What does Canadian gas demand in the future look like? How will exports to the U.S. change? Will production continue to grow, stay flat or decline in the near future? Stay tuned as PointLogic tackles these questions in many others in upcoming Get the Point issues.

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