Updated March 2017
Henry Hub natural gas prices declined in 2016 to US$2.41 per million British thermal units (MMBtu) from US$2.77/MMBtu in 2015. This was as a result of weak growth in demand that coupled with a mild winter led to storage inventories exceeding the five-year average across Canada and the United States. Given significant shale gas supply in the U.S. and high storage levels, the North American natural gas market is expected to remain well supplied. The wide-scale replacement of coal with natural gas in the power generation market in the United States is at risk as a result of the Trump administration’s energy policy; however, some replacement is still expected on a state-by-state level. The development of additional U.S. LNG facilities and anticipated growth in U.S. exports to Mexico are also expected to provide additional demand and lessen the supply/demand imbalance. However, the abundant supply situation is expected to continue throughout the forecast period, keeping prices relatively low.
Figure 1.5 [Tableau] shows the historical and forecast Henry Hub price for natural gas. Henry Hub prices are expected to average US$3.00/MMBtu in 2017, ranging from US$2.50/MMBtu to $3.35/MMBtu. In the low price scenario, prices are forecast to remain basically flat at 2016 levels because any demand increases are projected to be readily matched by supply, while in the high price scenario, demand is forecast to grow more rapidly, reducing the imbalance between supply and demand.
The Henry Hub natural gas price is forecast to gradually strengthen to US$4.35/MMBtu by 2026 in the base price scenario, reflecting increased international demand through a combination of U.S. LNG exports and U.S. exports to Mexico and increased U.S. demand, primarily in the power sector. In the low and high price scenarios, the price will reach US$3.52/MMBtu and US$6.20/MMBtu, respectively.
How the Henry Hub price was derived can be found in the methodology section.
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. The AECO-C price hit a low of $1.14 per gigajoule (GJ) in May, and in fact hit an all-time low of $0.50/GJ on May 9, as the wildfires forced the shut-in of oil sands facilities, which account for the largest component of domestic demand. The lower Alberta prices and therefore higher differential prompted an increase in exports to the United States as buyers took advantage of the cheaper supply from Alberta. As affected oil sands facilities came back on-stream in midsummer, the differential narrowed, bringing it close to historical levels.
In 2016, the AECO-C price declined to an average of Cdn$2.05/GJ, down 22 per cent from 2015. As was the case in previous years, oil sands demand, although not increasing as significantly, and gas-fired electricity generation are forecast to continue to account for the largest shares of natural gas demand in Alberta. As a result of the forecast growth in demand, the AECO-C price is projected to strengthen in 2017, as shown in Figure 1.6 [Tableau]. Prices are forecast to average Cdn$2.99/GJ in 2017, with a range of Cdn$2.37/GJ to Cdn$3.43/GJ. Over the forecast period, the price of natural gas is projected to increase and reach an average of Cdn$4.38/GJ by 2026, with a range of Cdn$3.40/GJ to Cdn$6.67/GJ.
The forecast assumes that gas production in the United States will continue to increase, acting as a price ceiling in the short term. In the long term, demand for natural gas is forecast to increase because, under Alberta’s Climate Leadership Plan, coal-fired electricity generation is to be phased out by 2030, prompting a switch to natural gas. Additionally, as the United States exports increasing volumes of its natural gas, there may be opportunities for Alberta to supply the U.S. natural gas market.
How the AECO-C price is derived can be found in the methodology section.