Low inventory levels in Western Canada have propped up AECO prices in Q1 19. We project a multi-year low end-March western carryout of 430 bcf, down by 50 bcf y/y. The situation will have only barely improved by the start of winter 2019/20. We forecast Western Canadian inventories of 610 bcf by end-October, up just 5 bcf y/y from 2018’s decadal low. Interruptible transmission outages from NGTL maintenance are a wild card that could disrupt injections this summer. Due to low storage, AECO prices hit a premium to Henry Hub for the first time in three years late in February. We project AECO prices will average a $1.80/mmbtu discount this summer, narrower by $0.15/mmbtu y/y. While supported prices in the west will likely coax some extra production from E&Ps, the WCSB’s rig deficit of 56 y/y will likely prevent any output gains later in 2019. We project Eastern storage to end March in line with its five-year average of 60 bcf, and it is likely to enter the next heating season with its usual 270 bcf in inventories, given continued flows of US gas from Rover. Gas use in oil sands processing will likely support demand this summer, as Alberta lifts oil production cuts and Canadian Natural and Cenovus bring new projects online.
AECO prices have been riding a rollercoaster so far in Q1 19. Underlying support has come from Western Canada’s expanding y/y storage deficit. The deficit looks set to continue through the injection season. Our end-March carryout forecast for Western Canada is 430 bcf, down by 50 bcf y/y, 85 bcf below the region’s five-year average and a multi-year low (see Fig 1). We also project end-October inventories of 610 bcf, which would be 5 bcf above last year’s multi-year low carryout and 90 bcf below the five-year average as producers struggle to replace gas inventories before the start of the next heating season.
The start of the NGTL system’s annual summer maintenance season in April could limit how much inventories are replenished this injection season. While work is expected to be less impactful and less frequent y/y in 2019 on total capacity (see E-mail alert: Blame TransCanada! …even though pipeline maintenance set to be lighter than 2018, 10 January 2019), the impact on interruptible transport is currently unknown. If interruptible service is affected by prolonged outages, producers are likely to be hesitant to send gas into storage, in case it is stranded there for long periods. In addition, cuts to interruptible transport would weigh on cash price.
While Western Canada entered this heating season already in a y/y deficit, February’s brutal cold has been the driving force behind further dwindling inventories. The month saw just one day with a high temperature above freezing (33°F on 22 February) in Calgary, and 24 days of sub-zero Fahrenheit lows. NGTL storage withdrawals for February averaged 2.0 bcf/d, up by 0.5 bcf/d y/y. AECO prices responded, rising to a premium to Henry Hub—of $0.01/mmbtu on 25 February—for the first time since December 2015. This ballooned to a $1.11/mmbtu premium on 1 March. Q1 19’s has averaged a $0.91/mmbtu basis discount to date, $0.51/mmbtu narrower y/y.
Higher Western Canadian prices are likely to help lift production, as several of the country’s largest E&P companies had pointed to poor economics as the main culprit behind projected spending and output declines for 2019 (see E-mail alert: Earnings point to small 2019 Canadian gas output declines, but less capitalised E&Ps may deepen losses, 14 March 2019). At the very least, AECO prices should be bolstered enough by the y/y storage gap to avoid the shutdowns that plagued Canadian production early in Q2 18. We project AECO prices will average $1.10/mmbtu in heating season 2019/20 (a $1.80/mmbtu basis discount), well above the $0.40/mmbtu cited by several producers as the breakeven for shutting-in wells (see E-mail alert: Canadian producers shift drilling and hedging strategies as AECO sinks lower in Q1 18, 30 May 2018).
While we expect some production uplift from low prices, the WCSB is still bound for y/y output declines. Our projection for 15.0 bcf/d of production in Western Canada for summer 2019 would represent a 0.3 bcf/d y/y drop in production. Rig deployment decisions affecting 2019 production were made in 2018. Indeed, Canada’s rig count of 232 at the end of January lagged 2018’s count by 106. The recent rise in prices has coincided with an easing to a 56 rig deficit y/y as March closes, with 105 rigs currently active. This indicates that rigs are being removed for mud season at a slower pace than last year—despite a similar start to mud-season on the calendar at the end of March—but this is likely not enough to support output gains.
February’s cold knocked Eastern Canada from a y/y storage surplus of 10 bcf at the end of January to a projected end-March inventory of 60 bcf, which would be in line with the five-year average. We expect Eastern Canada to enter the 2019/20 heating season with its typical 270 bcf in storage though, given Rover’s consistent flows of 1.0 bcf/d of US gas onto Vector and into Dawn. Gas from the WCSB will also help close the gap, particularly if interruptible transmission outages see producers avoid injections into storage in Western Canada. NGTL maintenance is set to be least disruptive to flows heading east. East Gate maintenance, which would hamper gas crossing the border from Alberta into Saskatchewan, is scheduled to cut an average of just 60 mmcf/d of capacity between April-October, with only four days of work taking offline more than 0.5 bcf/d (between 27-30 May on the Eastern Alberta Mainline).
Competition for gas demand this summer will come from the oil sands sector. Alberta provincial government-mandated oil production cuts of 0.33 mb/d (8.7% of total production) in Q1 19 were disproportionately aimed at bitumen output, dampening gas demand for processing oil sands (see E-mail alert: Low AECO prices are already weighing on Canadian gas production, regardless of Alberta oil cuts, 7 December 2018). However, the cuts were to be re-examined monthly in Q1 19 and have been reduced by 25 thousand b/d in May and a further 25 thousand b/d in June.
The easing of the cuts comes as several new oil sands projects are scheduled to come online. Canadian Natural expects to complete its 40 thousand b/d Kirby North project in Q2 19, two quarters ahead of scheduled. Cenovus is also likely to bring Phase G of its Christina Lake thermal project, a 50 thousand b/d expansion, online in Q3 19. Canadian Natural’s and Cenovus’s new facilities have helped bring our summer 2019 forecast for gas use in the oil sands sector to 2.6 bcf/d, flat y/y. This contrasts to our forecast at the end of 2018 that called for gas use for oil sands to shrink by 0.2 bcf/d y/y.
|Fig 1: Western Canada end-March storage, bcf||Fig 2: Canadian rig count|
|Source: NEB, Energy Aspects||Source: Baker Hughes, Energy Aspects|