North of the Border Gas Pushing Prices South

April 5th, 2018 |

2017 wasn’t a great year for natural gas pricing in Canada, with AECO prices averaging near $1.70/MMBtu and widening differentials to Henry Hub. Growing production in 2018, limited demand growth, quickly filling pipeline capacity, and strong US competition all placed significant pressure on the Western Canadian gas markets. 2018 isn’t poised to resolve many of these issues either. Despite this, Canadian producers have persevered and continued to grow Western Canadian natural gas production, placing more gas into an already crowded market.

The chart below shows that, while Henry Hub prices have remained relatively stable near $3.00/MMBtu over the past year, the spread to AECO has been growing since early 2017. For the first half of 2017, AECO traded just under $1.00/MMBtu back from Henry. For the second half of the year the spread averaged over $1.60/MMBtu back.

As the AECO market remains weak and volatile, producers are seeking ways to manage their risk. Canadian Natural Resources (TSE: CNQ) has reduced the company’s exposure to the AECO market to just 39% of their gas production for 2018. Canadian Natural Resources benefits from using almost a third of their produced gas for internal operations. Seven Generations (TSE: VII) has actively hedged through 2019 and secured firm transport to Dawn, Henry Hub and Malin to help reduce their AECO exposure (over 75% of total hedged volumes to markets other than AECO) Likewise, Tourmaline (TSE: TOU) has over 60% of the company’s natural gas volume either hedged or destined for US markets. However, there is still plenty of risk surrounding the Western Canadian producers. As we saw this fall, when TransCanada’s NGTL system underwent maintenance and expansion work, limited takeaway capacity was one of the factors which drove spot prices negative and forced temporary shut-ins.

Despite the challenging environment, production has been strong and natural gas flows reached nearly 17.5 Bcf/d in January on the main pipelines out of Western Canada. The chart below shows averaged daily production receipts for the main pipelines servicing Western Canada. NGTL, Alliance, and Westcoast pipeline receipts account for nearly all of the gas produced in Alberta and British Columbia, with the NGTL system capturing the majority, nearly 75% of the volumes given below. For the second half of 2017, flows were significantly higher year over year as producers ramped up activity and wells saw continuing IP rate improvements. Strong winter drilling helped push 2018 production receipts over 1 Bcf/d higher than witnessed in previous years for January and February.

Much like the Permian, drilling decisions in the Montney and Duvernay are being driven by the economic boost from liquids production, with the associated gas and the pricing of that gas being less important than in dry gas plays. What this means is that natural gas prices can dip towards $1.00/MMBtu at AECO and Western Canada production will still keep coming as cash flow from the liquids help Canadian producers keep growing despite low prices and a widening basis.

However, all of this production growth needs to find a home and domestic demand is unlikely to provide the necessary relief. One of the main drivers, Alberta in situ demand, is expected to grow at a slower pace due to increased efficiencies and slower oil sands growth. As shown in the flows above, that means a significant portion of new production from Western Canada will head towards the US. The downstream implications of this are especially severe in the next 12 months, as we’ve previously highlighted, that constraints exist between supply basins and growing demand in the Gulf Coast.

Until the new US pipeline projects are completed and open up constraints for the major US Shale plays to reach the Gulf Coast, Canada may be able to price itself even lower to secure US market share. For more information on how Canadian gas production fits into BTU’s North American Supply and Demand Balance, and the increasingly constrained gas pipeline network, request a free sample of the  Upstream Outlook Report.

 

Author: Jason Slingsby

Jason Slingsby is an Energy Analyst for BTU Analytics, and leads the publication of BTU's North American Upstream Outlook. He is responsible for overseeing regional oil and gas production forecasts as well as analyzing overall market conditions, supply and demand balance, producer rationale, and commodity price forecasting. In addition to managing BTU's flagship product, Jason is focused on researching upstream oil and gas production in Canada and natural gas demand trends in Mexico. Jason holds a Masters degree in Chemical Engineering from the Colorado School of Mines.