Canada – A tale of two Canadas

Published at 16:29 29 Oct 2019 by

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AECO prices are receiving twofold support in Western Canada. The index’s 2019–20 winter strip is at its narrowest discount to Henry Hub of the year ($0.65/mmbtu) as Alberta’s inventories will enter the winter down by 70 bcf y/y. The new NGTL service protocol, which prioritises storage injections during maintenance, has resulted in less gas stranded upstream, discouraging AECO price weakness. Eastern Canada remains the counterpoint to the west regarding both gas storage and price as Dawn inventories have already crossed 270 bcf (+15 bcf y/y). Dawn prices are averaging an all-time monthly low discount to Henry Hub of $0.40/mmbtu in October. We project Dawn will also average a discount to the Hub of one cent per mmbtu through the heating season. The east’s high inventories and low prices have resulted in lower US gas imports to the region, lifting total net Canadian exports. Moving into the winter, much will depend on if cold temperatures materialise to spur additional demand. Our forecast is based on 10-year normal weather, which would see res-com and industrial demand fall by 0.4 bcf/d y/y each.

AECO-C is one of the limited number of basis points in North America demonstrating upside potential for the coming heating season (with the exception of a few Northeast US points affected by TETCO maintenance). Alberta’s projected 445 bcf end-October storage carryout is set to be 70 bcf below last year’s decadal low for the province. The deficit is providing a base of demand from storage that is lifting prices ahead of the heating season. AECO’s winter basis strip began the 2019 injection season at a $1.40/mmbtu discount. However, that winter price has narrowed each month of the injection season to its current $0.65/mmbtu level (see Weekly basis update: AECO winter basis to be supported by low Alberta gas inventories, 11 October 2019).

However, AECO prices are rising for more reasons than the added demand from low inventories. A new temporary service protocol for the NGTL pipeline system came into effect on 1 October that prioritises interruptible transport and storage injections over receipts during times of pipeline maintenance. The old system resulted in some volumes becoming stranded upstream of demand centres, thereby crashing AECO prices after those volumes were sold for pennies. AECO support is thus not only being driven by a lack of inventories in the run-up to the heating season but also by the new protocol discouraging price weakness. Indeed, AECO cash prices are up $1.09/mmbtu m/m to $1.63/mmbtu. This includes only two days below $1.00/mmbtu (1–2 October), in contrast with earlier this injection season, which took place before the new regulations were adopted and during which AECO averaged just $0.80/mmbtu.

October has seen the protocol achieve its desired result for inventories, as month-to-date NGTL injections have averaged 0.7 bcf/d (see Figure 1). This amount would be the highest total for any month in two years, not to mention 0.4 bcf/d above the five-year average for October. This has come amid heavy maintenance activity. Restrictions in the Upper James River production region have averaged 0.4 bcf/d in October to-date, compared with 0.2 bcf/d last October, when the NGTL mustered just 0.15 bcf/d in net injections.

The surge of Alberta injections will not do much more than dent the province’s y/y storage deficit. Still, our estimate of a 70 bcf y/y deficit is a 10 bcf improvement from before the protocol came into effect (see Monthly: Canada – Divergent regional storage, 25 September 2019). The real results of the new protocol—which will be in effect between April and October in 2019 and 2020— will likely be felt in injection season 2020. We forecast the new rule will allow Alberta to break back to a y/y surplus (albeit off a low baseline) next summer for the first time since 2017.

We project an AECO discount of $0.60/mmbtu for the winter, and we also project a $0.97/mmbtu discount during injection season 2020 on the prospect of continuing low inventories and the floor provided by the new protocol.

Across the country, Dawn prices are falling as AECO prices rise. Dawn inventories sat at 273 bcf as of 18 October (+15 bcf y/y), leaving little room to inject before it hits maximum capacity of 279 bcf. The lack of demand from storage has sent Dawn prices spiralling. Dawn basis to-date in October is averaging an all-time low discount of $0.40/mmbtu to Henry Hub (eclipsing last month’s previous record low of $0.38/mmbtu). Given our assumption of normal weather, we expect Dawn’s inventory overhang to push the index to a one-cent discount to Henry Hub in the coming heating season—Dawn’s first basis winter discount in over 10 years.

Dawn prices are also averaging a discount to Chicago Citygate in October, which is incentivising gas to stay in the US Midwest rather than cross the border (see Figure 2). Flows through the St. Clair border crossing in Michigan are at a three-year monthly low of 0.75 bcf/d in October. This represents the lowest total since Rover Phase 2 and NEXUS added extra capacity to St. Clair in the summer of 2018.

The reduction in US exports north will boost net Canadian exports to the US through the 2019–20 heating season by 0.5 bcf/d y/y. Dawn should be able to lean on its full inventories to meet early heating season demand, reducing the need for US inflows. This, combined with expanded capacity on the Westcoast Pipeline after summer repairs, underpins our estimate for higher Canadian net exports y/y this winter (see Weekly basis update: Timely, effective Canadian pipeline maintenance sinks Sumas winter prices, 13 September 2019).

Of course, winter weather, and by extension winter demand, remains the unknown across Canada. Last winter saw Canadian HDDs that were 5% higher than average. A revision to 10-year normal temperatures drives our forecast for both res-com and industrial demand to fall by 0.4 bcf/d y/y each. We are already seeing declines in Canadian industrial demand among the wider global macroeconomic slowdown as StatCan data showed a 1.5 bcf/d y/y decline (30%) in the sector’s gas demand in July, the latest month with official records. Colder-than-average temperatures will likely be needed to keep demand in line y/y, although much will depend on which provinces are affected given the ongoing regional disparities in storage and gas prices.

Fig 1: Daily NGTL storage injections, bcf Fig 2: US exports through St. Clair (bcf/d) vs Dawn-Chicago Citygate price spread ($/mmbtu)
Source: TC Energy, Energy Aspects Source: Refinitiv, Ventyx, Energy Aspects

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