Register with us today

and in less than 60 seconds continue your access to:Latest news headlinesAnalytical topics and featuresCommodities videos, podcast & blogsSample market prices & dataSpecial reportsSubscriber notes & daily commodity email alerts

Already have an account?

Log in to register

Forgot Password

In this list
Natural Gas

Analysis: Stronger oil sands demand, low natural gas storage bolster AECO futures

Natural Gas | Natural Gas (European) | Natural Gas (North American)

Evolving dynamics in the European natural gas market: A dive into Ukraine

LNG | Natural Gas | NGL

Platts LNG Alert

Electric Power | Renewables | LNG | Infrastructure Utilities

Caribbean Energy Conference, 21st

Natural Gas | Natural Gas (North American)

ANALYSIS: AECO hub boasts strongest winter prices in years, gas' power share stands firm

Electric Power | Renewables | Natural Gas (North American) | Crude Oil | Steel | Petrochemicals

Commodity Tracker: 5 charts to watch this week

Analysis: Stronger oil sands demand, low natural gas storage bolster AECO futures

Denver — Demand likely to grow about 200 MMcf/d in 2020

Upward pressure on AECO likely

The expectation of stronger natural gas demand from the Alberta oil sands, coupled with stalling production because of lower rig activity, looks likely to push the region's storage deficit deep into 2020, providing upward pressure on AECO hub futures.

As working gas capacity storage levels in Alberta are near 15-year lows, upcoming extra demand from the Alberta oil sands could complicate the supply issue further.

The production of oil from Alberta's oil sands operations already accounts for 25% of Canadian natural gas demand, and the figure looks to increase next year as expansions in the province come online. With current demand at 3.79 Bcf/d, S&P Global Platts Analytics expects the number to surpass 4 Bcf/d by late 2020 because of expansion projects.

Steam created from the burning of gas is crucial in separating oil molecules from sand during the production process. An increasing number of cogeneration facilities in the oil sands use gas to produce heat and electricity for project operations and for sale to the power grid, according to Canada Energy Regulator.

Last month, Nova Gas Transmission Line made changes to its tariff amendment, which is expected to allow Alberta to inject at multiyear highs in the summer of 2020 in order to reduce the storage deficit. The higher injection rate, however, might not make much difference as Empress hub sendout could be flat, if not higher, to summer 2019's 2.8 Bcf/d average, which could drive AECO as high Chicago hub prices, according to S&P Global Platts Analytics.

Contracting data for Empress' three primary destinations, Great Lakes Gas Transmission, the TC Energy Mainline and Viking Gas Transmission, show there are about the same number of contracts in summer 2020 as there were in 2019, although more could be signed up.

While 350 MMcf/d of additional summer 2019 contracts were signed last winter, the spread from AECO to Chicago is looking considerably narrower this upcoming summer than in past summers. AECO summer 2020 futures are trading at just a USD 92 cents/MMBtu discount to those of Chicago, down from $1.27/MMBtu last summer.

TC Energy charges $1.09/MMBtu to flow from Empress to the eastern edge of Michigan at St. Clair, so this would be out of the money this coming summer, whereas it was in the money last summer.

Low variable costs mean contracted volumes are likely to flow, absent a significant tightening of AECO to Chicago, and flat exports out of Empress could mean a very tight AECO next summer. With an extra 270 MMcf/d flowing out of the Alberta/British Columbia Border from June 2020's West Path Delivery project and an extra 500 MMcf/d of demand growth from the oil sands and coal-to-gas conversions, AECO would be 0.8 Bcf/d tighter next summer, according to Platts Analytics.

If Alberta injects even at just five-year average levels next summer, this would add another 150 MMcf/d of injection demand over summer 2019. This leaves production needing to grow 0.8 Bcf/d to keep AECO flat summer on summer.

If production does not grow next summer, the next most likely way for AECO to meet its demand and injection needs would be to cut outflows to the Midwest. This points to the possibility AECO could tighten near even to Chicago, as the variable cost to the Midwest from Empress is a mere 14 cents/MMBtu, and this is the cost AECO will need to cover if it is to keep contracted volumes from flowing out of Empress into the Midwest.

-- Brandon Evans,

-- Richard Frey,

-- Edited by Bill Montgomery,