The Spirit River Formation in Alberta’s Deep Basin has witnessed steady production growth since 2010 and currently accounts for just under 15% of Canada’s total natural gas supply, with over 2.1 billion cubic feet (bcf) per day of gas production. Although the Montney shale continues to garner the most widespread attention among unconventional Canadian gas plays, Spirit River—which consists of several Lower Cretaceous tight sandstone subunits—exhibits competitive recovery rates and economics.
Figure 1 shows historic quarterly production and drilling and completion (D&C) trends for the Spirit River Formation. Despite reliably sluggish AECO gas prices, drilling and completion activity has picked up in the play over 2017. During the first nine months of 2017, the number of spudded and completed horizontal wells increased by approximately 40% and 20%, respectively, compared to the same period in 2016, whereas average y/y production over the first three quarters of this year increased by 10%.
Two operators have historically dominated Spirit River activity. Peyto Exploration & Development is almost exclusively focused on the play with extensive contiguous acreage in the Greater Sundance and Brazeau River areas. Between 2010-2017, Peyto has drilled and completed over 500 gross horizontal wells with an associated cumulative EUR of ~1.6 trillion cubic feet (tcf) (see Figure 2). In addition to its acreage positions in the Montney and Peace River High Complex, Tourmaline Oil has significant exposure to Spirit River’s stacked formations, extending from Brazeau River in the southern part of the Deep Basin to Kakwa in the north. The company has also experimented with more intensive completion techniques and exhibits a more favorable cumulative completion-to-EUR ratio.
Among newer entrants to the play, Jupiter Resources demonstrates the most impressive well performance (see Figure 3), while Cenovus Energy (formerly ConocoPhillips acreage), Westbrick Energy, and Repsol (formerly Talisman Energy acreage) wells exhibit cumulative completion-to-EUR curves similar to those of Tourmaline Oil.
Well performance, as measured by 30-day initial production (IP) rates and average lateral length, has been somewhat mixed among the most active drillers. IP rates have essentially tracked lateral length trends for operators such as Repsol, Peyto, Bonavista, and—to a certain degree—Jupiter Resources (see Figure 4). Conversely, Tourmaline Oil and Cenovus/ConocoPhillips have decreased average Spirit River lateral lengths since 2014 while simultaneously increasing and/or stabilizing IP rates.
Although aggregate IPs and lateral lengths have not increased drastically—taken as a whole, Spirit River has exhibited around 2% CAGR for both metrics from 2014-2017—Spirit River economics are still competitive. Figure 5 compares Spirit River and Montney economics in terms of both well and operating cost trends. Although well costs (MUSD) have decreased in both plays since 2013, Rystad Energy forecasts average 2017 Spirit River DC&T costs to be roughly 30% lower than average Montney horizontal well costs.
Production operating expenses (USD/boe) have followed a similar trend for both plays since the oil price collapse in 2014. As with well capex, however, Spirit River opex has tracked lower than the Montney shale and is forecasted to be on average 33-34% lower in 2017. Moreover, many E&P players in the play own and operate their own processing facilities, which gives more flexibility to respond to low regional gas prices. As such, the average breakeven gas price (2016-17 completion years) stood at 1.65 USD/kcf (see Figure 6) versus a slightly higher breakeven of 1.81 Usd/kcf for Montney.
Although somewhat overshadowed by activity in Canada’s larger unconventional plays, Spirit River represents an important component of western Canadian gas supply and has continued to attract investment throughout 2017. Unlike the neighboring Montney and Duvernay plays, whose liquids-rich areas provide greater opportunities for more attractive netbacks, the vast majority of Spirit River production consists of dry gas and is thus more vulnerable to a regional gas market that will be oversupplied for the foreseeable future. Nevertheless, the play has proven competitive in terms of both well capex and operating costs and could potentially double production to 2025 under Rystad Energy’s base case price scenario.