Canada – Wild, wild west

Published at 14:44 30 Jul 2019 by . Last edited 11:18 22 Aug 2019.

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Western Canadian production is lagging in July by even more the rest of 2019’s trend of declining y/y output. Flow data—which account for over 90% of WCSB output—point to a 0.75 bcf/d y/y (5%) decline for the month. While lower rig counts, drilling, and investment are to blame for the long-term trend, July has seen weather disruptions, processing plant turnarounds, and high maintenance also weaken production. We forecast a 0.4 bcf/d y/y decline from the WCSB in H2 19. This does not account for a potential voluntary supply cut from Canadian producers. We do not feel producers with contractual commitments are likely to comply with such a deal given its lack of enforcement mechanisms. Talks of an output cut stem from the negative effects of TC Energy maintenance on the ability to send Alberta gas into storage. We project Alberta will enter the winter with inventories of 465 bcf, down by 50 bcf y/y and the lowest carryout in a decade. This should support AECO prices through the winter, as we forecast an average discount of $1.09/mmbtu to Henry Hub in the 2019–20 winter, $0.54/mmbtu narrower y/y. Falling production and low storage will keep prices relatively supported during the remainder of the summer as well.

In a year when every month has seen declining y/y gas production, July has been particularly bleak for output in Western Canada. Our flow sample from the WCSB—which covers over 90% of regional production—points to a 0.75 bcf/d y/y (5%) decline this month, and every day thus far in July has seen production decline y/y. We have long anticipated production declines from the WCSB through 2019 given the negative trends in drilling and exploration (see North America Monthly: Canada – Arrested production, 28 November 2018). Those trends have continued into 2019, as wells drilled in British Columbia fell by 10% y/y in H1 19 to 223. Alberta data show 285 wells drilled in 2019 through April (the last month for which data is available), down by 20% y/y. Canada’s current rig count of 127 represents a decline of 96 rigs y/y.

While part of a larger pattern, the sharp July decline has been exacerbated by several short-term disruptions, including a 15 July torrential downpour and tornado in the Duvernay play that hampered production by 0.5 bcf/d d/d. After recovering, output fell by 0.3 bcf/d d/d on 22 July amid plant turnarounds in Alberta that offlined a similar amount of processing capacity. NGTL maintenance has also been intensive in July; work on the Edson Mainline Loop reduced pipeline capacity out of Alberta by 0.3 bcf/d between 2–25 July, and there were compression station upgrades almost daily.

We forecast a 0.4 bcf/d y/y decline in WCSB output in H2 19, even when the more transitory disruptions fade, as the Canadian gas market is still dealing with oversupply issues that have crippled AECO-C prices. In response to persistently low AECO prices—June cash price for the index averaged a decadal low of $0.46/mmbtu, down by $0.87/mmbtu m/m—several large E&Ps have ramped up discussions with TC Energy and the Alberta Energy Regulator on a voluntary production cut (see E-mail alert: Talks of a voluntary gas production cut in Alberta accelerate, 18 July 2019). Such talks have centred on producers voluntarily shutting in production on days with high NGTL maintenance to avoid stranding excess gas in upstream production areas. Any potential deal does not factor into our current production forecast, however, given the lack of enforcement mechanisms means those producers with gathering, midstream and other cost-based commitments are not likely to comply.

At the heart of producer complaints is TC Energy’s annual summer maintenance on the NGTL system, which producers feel hinders their ability to refill storage. Summer 2019’s upgrades have limited capacity at the Upper James River (UJR) flow point by about 0.4 bcf/d thus far this summer. As a result, monthly inventory additions have fallen y/y in every month of the injection season thus far, according to NGTL daily figures. July’s 0.5 bcf/d injection would be the highest total in a year but still lags the month’s five-year average by 0.2 bcf/d. No month’s injections have been above the five-year average this summer, nor was any month in summer 2018 (which was similarly maintenance afflicted).

Thus, Alberta’s inventories have struggled to recover this summer. The province currently has 415 bcf in storage, down by 65 bcf y/y. This deficit is unique to Alberta, as British Columbia inventories of 65 bcf are up by 15 bcf y/y, while Saskatchewan storage of 30 bcf is flat y/y (see Fig 1). Alberta entered last winter with a multi-year low carryout and is on pace to do so again. We predict its inventories will end October at 465 bcf, down by 50 bcf y/y. That new record-low carryout will help support AECO prices during the heating season. We forecast AECO will average a discount of $1.09/mmbtu to Henry Hub in the 2019–20 winter, $0.54/mmbtu narrower y/y on the reduced ability of Alberta to lean on inventories when cold weather arrives.

In the short term, AECO has rebounded from its record-low June cash level to an average price of $0.83/mmbtu in July and should receive further support from the production declines and the demand for gas to refill storage in Alberta. Lesser maintenance upstream at UJR is also likely to result in fewer days of excess stranded gas in production areas through the end of the summer, which means fewer days of intense volatility for AECO (see Fig 2). These support indicators drive our forecast for AECO to average a $1.38/mmbtu discount to Henry Hub through the end of the summer, $0.70/mmbtu narrower y/y.

Fig 1: Western Canadian storage y/y, bcf Fig 2: Upper James River restrictions, bcf/d
Source: StatCan, Energy Aspects Source: TC Energy, Energy Aspects

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