Updated March 2018
The AECO-C price increased in January 2017, extending a trend that started in December 2016, as colder weather increased heating demand. However, the price fell in February as temperatures warmed to above normal. The price averaged Cdn$2.73/GJ in the first quarter of 2017 compared with Cdn$1.98/GJ in the first quarter of 2016, which prompted an increase in drilling, with January drilling up 62 per cent from January 2016. In the first quarter of 2017, Alberta demand was 5 per cent higher than in the first quarter of 2016. Exports to the United States were also 9 per cent higher, driven by exports to the U.S mid-continent.
The AECO-C price decreased slightly in the second quarter of 2017, averaging Cdn$2.64/GJ, as the winter heating season ended; however, the price was over one dollar higher than in the second quarter of 2016, and Alberta natural gas storage was within the five-year average, compared with 2016 when storage remained above the five-year average for most of the year, helping to strengthen the price. In addition, natural gas demand was 5 per cent higher compared with 2016, when natural gas demand was affected by the Fort McMurray wildfires in May, depressing the price. The AECO-C price fell slightly in June 2017, however, due to service disruptions on the Alliance pipeline system.
The AECO-C price fell again in the third quarter of 2017, averaging Cdn$1.80/GJ. Despite warmer weather and increased cooling demand, the price fell sharply in July and continued to fall due to an outage at a compressor station on the NOVA Gas Transmission Ltd. (NGTL) system near Rocky Mountain House. Service continued to be disrupted for the rest of the third quarter and the beginning of the fourth quarter due to an upgrade project, TransCanada Corporation’s (TransCanada’s) NGTL System Expansion Project, which increased capacity by 700 million cubic feet (MMcf) per day on the northwest portion of the system. The price was highly volatile and occasionally negative as continued maintenance on the system interrupted service, limiting natural gas deliveries from Alberta to eastern Canada. As a result, gas was injected into storage, which by the end of the third quarter was 94 per cent full. The differential between the AECO-C price and the Henry Hub price widened significantly between July and September to average US$1.44 per million British thermal units (MMBtu) compared with an average of US$0.78/MMBtu in 2016. However, the wider differential in 2017 combined with a lower exchange rate made Canadian gas competitive with U.S. prices, with some Canadian gas reaching the Sabine Pass liquefied natural gas (LNG) terminal for export to international markets.
The AECO-C price increased slightly in the fourth quarter of 2017, averaging an estimated Cdn$1.83/GJ, as maintenance on TransCanada’s Mainline was completed and new long-haul contracts came into effect on the line in November. Under the new contracts, an additional 1.4 billion cubic feet per day (Bcf/d) of gas will be transported to the Dawn Hub. As a result, the western Canadian portion of TransCanada’s Mainline operated at full capacity, 3.8 Bcf/d, in November, compared with 1.7 Bcf/d in July, when previous long-haul contracts expired. Warmer weather in the second half of November and early December, along with residual pipeline restrictions, weakened the price. However, unusually cold weather in Canada in late December increased heating demand, strengthening the price.
As shown in Figure 1.7 [Tableau], the AECO-C price averaged an estimated Cdn$2.25/GJ in 2017 and is forecast to increase to Cdn$2.86/GJ in 2018, Cdn$3.32/GJ in 2019, and Cdn$3.86/GJ in 2020. The price is then projected to gradually increase to Cdn$5.03/GJ in 2027, with a range of Cdn$3.38/GJ and Cdn$6.68/GJ. The AECO-C price benefits from a strong Henry Hub price, but the price differential is expected to widen in 2019 and 2020 before beginning to narrow as domestic demand strengthens and pipeline expansion projects are completed over the forecast period.
Western gas producers are expected to maintain their current market in eastern Canada over the forecast period, with U.S. imports filling the rest of the supply gap to eastern Canada due to new pipeline expansion projects underway between the United States and Canada, which will bring low-cost shale gas into Canada. Infrastructure expansions should allow western producers to maintain and increase their market share in the U.S. mid-continent, as well as to continue to expand into Pacific Northwest markets. Over the forecast period, greater infrastructure connectivity is expected to provide opportunities for Alberta gas producers to reach beyond North American markets, resulting from Alberta natural gas becoming a competitive alternative for export from U.S. LNG terminals. These market expansions, combined with increased domestic demand for natural gas in Alberta, will strengthen the AECO-C price.
The differential between the AECO-C price and the Henry Hub price is expected to relax somewhat in 2018 to US$0.90/MMBtu because any transportation disruptions on the TransCanada Mainline should not negatively affect prices as they did in 2017. However, the average differential is expected to be higher than the five-year average (2012–2016) due to the Henry Hub price being strengthened by increased exports. Further, with an additional 1.4 Bcf/d of natural gas being delivered to the Dawn Hub as a result of the new long-haul contracts, the expectation is that western gas has secured a market between 3.0 Bcf/d and 4.0 Bcf/d. However, the differential is projected to widen in 2019 and 2020 to US$1.20/MMBtu as U.S. LNG export capacity grows to 9.5 Bcf/d and the Henry Hub price is affected by exports reaching new international markets, creating a disconnect with the AECO-C price. The AECO-C price is projected to increase by only Cdn$0.61/GJ in 2018 as the price is affected by the forecast increase in Alberta natural gas production and the increased flow of gas into Alberta from new pipeline interconnects in British Colombia. The differential is anticipated to begin to narrow in 2021 as pipeline expansion projects are completed and domestic demand increases.
Several proposed pipeline expansion projects over the forecast period are expected to strengthen the AECO-C price through increased market share in the U.S. mid-continent and northwestern markets. The proposed expansion of the Alliance pipeline system, with an expected 2020 start-up, is anticipated to increase capacity by up to 0.5 Bcf/d, carrying additional volumes to the Chicago market. In addition, one of TransCanada’s pipeline expansions will increase flows by 381 MMcf/d at the Alberta–British Columbia export delivery point, which connects Canadian supply to the Pacific Northwest, California, and Nevada markets.
Domestic demand for natural gas is also anticipated to increase over the forecast period, driven by demand for natural gas for power generation and for use by petrochemical plants and oil sands projects. In 2017, ATCO Power announced that it plans to convert its Battle River and Sheerness power generation plants from coal-fired generation to natural gas-fired generation, ahead of the Government of Alberta’s 2030 schedule to phase out coal-fired power generation as part of its Climate Leadership Plan. TransAlta Corporation (TransAlta) also announced that it plans to convert its Sundance Units 3 to 6 and Keephills Units 1 and 2 to gas-fired generation between 2021 and 2023. Following these conversions, TransAlta expects that it will need about 0.7 Bcf/d of gas at peak levels of demand. In addition, a planned propane dehydrogenation plant in Alberta will require about 0.5 Bcf/d of gas.
In the long term, the AECO-C price will continue to be supported by the conversion of more coal-fired plants to natural gas-fired plants under Alberta’s Climate Leadership Plan. In addition, oil sands demand for natural gas is expected to continue to be high.
The high and low price scenarios shown in Figure 1.7 [Tableau] represent the short-term and long-term volatility of the AECO-C price. The high price scenario assumes decreasing North American natural gas production, increasing access to traditional markets and new markets, and increasing domestic demand through strong oil sands demand and accelerated coal retirement. The low price scenario assumes that North American natural gas production will be higher than expected, pipeline expansion projects will not be completed, demand from the oil sands will decline, and conversion from coal-fired to gas-fired power generation will be slow.
For information on how the AECO-C price is derived, see the Methodology section.