Updated August 2017
Natural gas prices declined in 2016 as a result of weak demand growth, which coupled with a mild winter, led to storage inventories exceeding the five-year average across Canada and the United States. This resulted in a second year of decreasing natural gas well activity. Alberta storage levels in early 2016 were high, widening the differential between AECO-C prices and Henry Hub prices, which then widened further as a result of the Fort McMurray wildfires. AECO-C hit an all-time low of $0.50 per gigajoule (GJ) on May 9, 2016, and averaged $1.14/GJ for the month, as the wildfires forced the shut-in of oil sands facilities, which make up the largest component of domestic natural gas demand. With the Henry Hub price strengthening in May to US$ 2.00 per million British thermal units (mmBtu), the differential prompted an increase in exports to the United States as buyers took advantage of the cheaper supply from Alberta. As impacted oil sands facilities came back on stream midsummer, the differential narrowed, bringing it closer to historical levels as a result of increased domestic demand.
In 2016, natural gas from conventional gas and oil wells placed on production represented an estimated 91.4 per cent of total production, with the remainder coming from coalbed methane (CBM) and shale gas wells. CBM production continued to decline in 2016, falling an estimated 6.3 per cent, while production from shale continued to grow, increasing by 3.1 million cubic metres per day (106 m3/d) or 66 per cent. Sour natural gas represented 19 per cent of total gas production in 2015, the last year for which sour gas data are available. This percentage has been relatively stable since 2012 at around 19 per cent, following a decline from 31 per cent of production in 2000.
There were approximately 120 000 producing gas wells in 2016, down from just over 123 000 in 2015, as can be seen in Figure S5.2 [Tableau]. Although the reduction in producing wells appears more pronounced in 2016 than in the past, it is more the result of a decrease in the number of wells being placed on production than an increase in the number of wells being taken off production. Although more pronounced in 2016, this downward trend began in 2010 as producers focus on drilling fewer, more productive wells.
As can be seen in Figure S5.1 [Tableau], with the exception of production from the Upper Mannville, Montney (PSAC Areas 2 and 7), and Duvernay Formation (shale), production in all areas of the province decreased in 2016. The increase in these areas is being driven by the presence of wet gas, making wells in these areas more economic due to the value of the natural gas liquids, and the higher initial productivities associated with horizontal drilling and hydraulic multistage fracturing. Gas from oil wells declined by 9.2 per cent as a result of declining oil production. Figure S5.3 [Tableau] shows historical raw natural gas production by on production year.
A summary of 2016 historical and forecast initial productivities by area can be found in the methodology section.
Consistent with the trend over the past few years, production from the wetter formations in PSAC Area 2 is forecast to contribute the majority of production. Total production, however, is forecast to decline between 2016 and 2021, despite forecast well activity growing in the near term, because well additions are insufficient to offset declines in existing production. The retirement of coal plants, assumed to begin in 2020, is forecast to add natural gas demand for electricity generation throughout the remainder of the forecast. This will result in stronger prices, which will support additional well activity and a stable but slightly decreasing production level for the balance of the forecast, with production reaching 250.7 106 m3/d in 2026. The methane management program put forward in the Government of Alberta’s Climate Leadership Plan could affect the production forecast. As the program proceeds, it may increase natural gas supply.
The forecast for total natural gas production does not include gas production from bitumen upgrading and raw natural gas from bitumen wells because this gas is typically used on site. The forecast for gas production from the oil sands can be found under the oil sands gas production and use section.
Figure S5.7 [Tableau] shows gas produced from bitumen upgrading (referred to as process gas) and raw natural gas from bitumen wells (referred to as produced gas). Gas from these sources is typically used as fuel in oil sands development, although increasing volumes are being sent to processing facilities for the removal of liquids.
Process gas production is estimated to have declined in 2016 to 15.6 million cubic metres per day (106 m3/d) from 18.7 106 m3/d in 2015 as a result of the indefinite shut-in of the Nexen Long Lake upgrader in January following a service disruption and the temporary shut-in of the other upgraders as a result of the Fort McMurray wildfires. Process gas volumes are expected to reach 20.9 106 m3/d by 2026, which is down significantly from the AER’s previous forecast of 25.8 106 m3/d by 2025, largely as a result of the shut-in of the Nexen upgrader.
Natural gas production from primary and thermal bitumen wells also decreased to 6.2 106 m3/d in 2016 from 7.1 106 m3/d in 2015, which was primarily due to fewer wells, the wildfires, and the shut-in of the Nexen upgrader, whose synthetic gas production had been included under produced gas. Produced gas is forecast to reach 7.8 106 m3/d by 2026, which is lower than the AER’s previous forecast of 11.4 106 m3/d as a result of a lower in situ bitumen forecast and the shut-in of the Nexen upgrader. Produced gas is used primarily as fuel to create steam for on-site operations.
The average use rates for purchased gas in 2016 are provided in Table S5.10 [HTML]. The gas use rates for steam-assisted gravity drainage (SAGD) are similar to those for 2015, while cyclic steam stimulation (CSS) rates have increased, reflecting the alternating pattern between steaming and production.
Total gas use for the oil sands sector is provided in Figure S5.8 [Tableau], including gas used for in situ recovery, mining and upgrading, and electricity generation. Supply is sourced from purchased gas, process gas from mining and upgrading operations, and produced gas from bitumen wells. Gas use by the oil sands sector was 84.9 106 m3/d in 2016, which was the same year over year as the increase in purchased gas for in situ recovery and for electricity cogeneration offset the result of the wildfires. Demand is expected to increase to 125.2 106 m3/d by 2026, which is lower than the AER’s previous forecast of 138.1 106 m3/d by 2025 because the oil sands production forecast has been revised downward.