Canada – Market tremors

Published at 14:40 19 Dec 2018 by

Users licensed for the data service can access our Canada gas balances by clicking here.

December is on track to be the second straight month in which the WCSB posts y/y output reductions. Month-to-date production in our sample (which covers approximately 90% of regional output) of 15.2 bcf/d is down by 0.1 bcf/d y/y. 2019 production guidance does not look promising for a recovery in output, with Canadian Natural Resources Limited (CNRL) pointing to gas output declines of 2% y/y and Crew calling for long-term shut-ins. Crew had been optimistic about its Montney drilling program, but its plans are on hold after a series of earthquakes in the area in early December. The region’s operators agreed to a 30-day drilling moratorium as British Columbia (BC) regulators investigate. Our balances currently call for a 0.1 bcf/d y/y output drop in BC in H2 19, which would be deepened by a more prolonged stoppage. The biggest demand impacts in early 2019 will be felt in the oil sands sector, as Alberta’s government-mandated oil cuts will take out 0.33 mb/d in bitumen output through Q1 19. Our balances call for a 0.3 bcf/d y/y drop in gas demand from the oil sands sector in Q1 19. In western Canada, the decline in demand is freeing up more gas for exports just as repairs to T-South are allowing for a 0.2 bcf/d m/m jump in flows through the Sumas border point. Falling demand is also helping reduce the y/y deficit in Canadian gas storage. Western Canada has seen several days of counter-seasonal injections in December, while eastern stockdraws have been in line with historical averages to start the heating season despite a bout of early winter cold in Ontario. The lack of need to heavily draw from inventories has seen Dawn flip from a $0.15/mmbtu premium to Henry Hub in November to a seven-cent discount in December. We maintain that Dawn will stay in a close range to Henry Hub, though colder weather could drive price spikes during the rest of the heating season.

WCSB gas production has sputtered to start the heating season, with December likely to be the second consecutive month to post y/y output losses. According to our flow sample, which covers just over 90% of regional production, month-to-date December output in western Canada is down by 0.1 bcf/d y/y. There are several factors conspiring to depress WCSB gas volumes, including NGTL maintenance, declining drilling activity and the October pipeline rupture on Westcoast Energy’s T-South (see Monthly: Canada – Arrested production, 29 November 2018).

The losses should continue into 2019, as low prices push Canadian producers to rein in output, according to published 2019 production guidance (see E-mail alert: Low AECO prices are already weighing on Canadian gas production, regardless of Alberta oil cuts, 7 December 2018). CNRL’s 2019 guidance calls for a 2% y/y production decline (30 mmcf/d), as the company cited price weakness in its decision to reduce its capital outlay by $1 billion to $3.7 billion. Crew announced it would maintain its average production of 0.1 bcf/d through 2019, though it also noted it was planning to shut-in 10 mmcf/d of gas production for the entirety of 2019 given current low AECO prices. The three-year plan for Advantage Oil & Gas shows a modest 2% y/y output drop in 2019, as the company seeks to diversify its revenue streams to reduce volatility.

Even some of the more optimistic 2019 capital plans were thrown for a loop after drilling was suspended in the Montney formation’s Septimus field following a series of small earthquakes in early December. The BC Oil and Gas Commission (BCOGC) launched a preliminary 30-day investigation into the source of the tremors after noting CNRL was drilling in the area at the time of the first quake. CNRL may only resume its work with BCOGC’s approval, while other companies operating in the region, including Crew, Cenovus and ARC Resources, all committed to postponing activity in the Septimus until the investigation is completed. If the BCOGC implements a lengthier halt to drilling, BC volumes will likely fall further in H2 19. Crew specifically noted in its 2019 guidance that it was hoping to focus on its Septimus acreage to keep production steady y/y. Our balances currently call for a 0.1 bcf/d y/y drop in BC output in H2 19, which could be exacerbated by a prolonged suspension of drilling in the Septimus.

While we do not believe the heavily publicised government-mandated oil cuts will directly depress gas output in Alberta, they are certain to lower demand for gas from oil sands processing. Roughly 83% of Alberta’s crude oil production is from bitumen, which consumes gas. Oil sands are now facing a 0.33 mb/d production cut (8.7% of total provincial output), which the government hopes will reduce inventory levels. There is some uncertainty surrounding the size of the cuts after several producers complained about shouldering an unfair burden of the 0.33 mb/d, and the Alberta government has promised to review the figure on a monthly basis. We forecast gas demand for oil sands processing will drop by 0.3 bcf/d y/y to 2.5 bcf/d in Q1 19. The mandated output cut is scheduled to fall from 0.33 mb/d to 0.1 mb/d after Q1 19. As such, our forecast for oil sands gas demand in 2019 shrinks to 0.1 bcf/d in y/y losses after Q1 19.

Lower domestic demand is freeing up more gas to be exported to the US, just as infrastructure constraints are easing in western Canada. Westcoast Energy’s repairs to its ruptured T-South pipeline boosted capacity to 1.5 bcf/d starting on 1 December, which is below its pre-accident baseline of 1.8 bcf/d but above November’s capacity of 1.2 bcf/d. Flows through the connected Sumas border point were up by 0.2 bcf/d m/m to 0.6 bcf/d in December to date. Total Canadian exports of 5.2 bcf/d in December to date are still down by 1.0 bcf/d y/y, the exact amount that Rover has allowed in Canadian imports of US gas (see Monthly: Canada – Rover to the rescue, 21 June, 2018).

Western Canadian storage will also benefit from the decrease in demand from oil sands in Q1 19. Regional inventories entered the 2018 injection season at a 65 bcf y/y deficit and extended that shortfall to 100 bcf at the start of the heating season after a fierce bout of early cold saw HDDs in Alberta rise 74% above the 10-year average in September. The weather in western Canada has become milder in December, allowing for more moderate stockdraws. Daily NGTL storage receipts from Alberta show that occasional counter-seasonal injections continued into December, as western Canada is on track to take just 0.9 bcf/d out of storage for December. This will cut the region’s y/y deficit to 70 bcf to start 2019 in our forecast.

Eastern inventories entered the 2018 injection season in an equally precarious state, though the east’s 60 bcf y/y shortfall at the start of May was eliminated by the start of the heating season thanks to the start-up of flows on the 0.8 bcf/d Rover into Dawn. Eastern inventories of 245 bcf at the end of December were in line with the region’s five-year average despite early winter cold that saw Ontario HDDs in November that were more than 20% above the 10-year average. Gas from the US has helped meet the accompanying rise in heating demand, with only moderate storage pulls. Eastern Canada's total November pull of just over 10 bcf was also in line with the five-year average. This was boosted by the higher import baseline from the 1.0 bcf/d currently flowing from Rover and NEXUS onto the Vector pipeline into Dawn.

Dawn price lost one of its pillars of support now that eastern inventories are on more stable footing. Dawn’s November $0.15/mmbtu average premium to Henry Hub has flipped to a seven-cent discount m/m as the storage situation has improved and NEXUS flows to Vector began in mid-November. We have long maintained that Dawn’s pricing would decouple from regional storage woes as US flows increase, and we continue to see Dawn trading in a narrow range to Henry Hub, with spikes only possible if intense cold lasts deep into the Ontario heating season.

Fig 1: Oil sands gas demand forecast y/y, bcf/d Fig 2: NGTL daily storage activity, bcf/d
Source: Energy Aspects
Note: Oct and Nov are still forecasts as data is not yet official.
Source: TransCanada, Energy Asepcts
Note: A negative number indicates net withdrawals.

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