Light tight oil production in North America has been hit hard this year as a result of the dramatic fall in oil prices caused by global oversupply and demand destruction. Activity levels and output are anticipated to show notable decline in 2020 that is likely to continue into 2021 as well. This article addresses Rystad Energy’s most recent forecast for NA shale oil and gas production and capital investments with the focus on the key contributing shale plays.
Figure 1 depicts light tight oil production (LTO) in North America (NA) by key shale plays from 2014 to 2030 along with our latest forecast for WTI oil price development. Since the downturn that prevailed between 2014 and 2016, LTO production in the region has revamped with a new force, able to adjust to a depressed price environment through high grading of acreage and considerable cost and productivity improvements. In 2019, oil output reached 8.6 million bpd representing a year-on-year growth of about 20%. However, the challenges of 2020 characterized by global oversupply and oil demand destruction have led to a dramatic fall in oil prices, forcing NA producers to cut capital budgets and adjust drilling and completion programs down while focusing on cash flows and returns. Furthermore, many producers in NA have been forced to curtail production volumes in addition to taking frac holidays and cutting the number of rigs and frac crews. Production shut-ins and restricted flowbacks on other wells peaked in May 2020 with many operators starting to return curtailed volumes from June as oil prices improved. We expect that majority of curtailments have been returned online by the end of August 2020. Oil production has thus increased during the summer months as a result of shut-in reactivations and higher levels of completion of already drilled wells. Nevertheless, new drilling activity levels remain low, and we expect oil output to show decline again in Q4 2020. Thus, overall LTO production in NA is anticipated to fall to 8.2 million bpd this year and decline further to 7.7 million bpd in 2021 as producers are poised to keep activity levels low amid uncertain market environment and a focus on capital discipline. As oil prices improve in the medium term, activity and oil production in NA are estimated to increase again, reaching 13.6 million bpd by 2030. The Permian Basin will be the major contributor to expansive growth going forward with Permian Delaware also remaining the most resilient play during the ongoing downturn.
Figure 2 shows gas production in North America by the key shale plays and Henry Hub gas price development. Total gas production stood at 79 billion cfd in 2019 and is estimated to decrease to 78 billion cfd this year. The output is anticipated at 77 billion cfd next year with the overall production representing slight decline versus 2020. Following that, production is expected to ramp up along with activity, as operators are encouraged by significant price improvements. Current outlook reflects market and industry sentiments that NA gas is not positioned for a significant upcycle until 2021. Among major gas basins, the Haynesville and Marcellus are estimated to see greater annual growth compared to Canada’s Montney and Utica Shale. Stronger activity has generally been observed in the Haynesville and Marcellus, where closer proximity to the Gulf Coast and wetter positions tend to promote lower median breakevens. Overall fracking has trended downwards in gas basins as operators have been more deliberate in maintaining modest production instead of eyeing strong growth post 2021.
Figure 3 displays the capital investments (drilling and completion costs) in North America shale over the period 2011-2030, split by shale play. Investments peaked in 2014 at around $180 billion, falling to a low of $60 billion in 2016 as the oil price collapsed from $100 per barrel in the first half of 2014 to an average of $45 per barrel in 2016. Following the recovery in 2017 – 2019, the oil price drop earlier this year set the stage for another low in the investment cycle. Drilling and completion costs are slated to fall across all plays this year with the heaviest cuts seen in major oil basins such as the Permian Delaware (-55%), Permian Midland (-54%), Eagle Ford (-62%) and Bakken (-62%). Similarly, major gas plays also see deeps cuts, including the Marcellus (-39%), Haynesville (-47%), and Montney in Canada (-51%). We do not expect significant recovery in spending until 2022, both a function of improving prices, as well as the significant drilled but uncompleted (DUC) wells established during this downturn, with the latest DUC well inventory standing at over 5,600 wells for major US oil basins.
As operators in the North American shale landscape continue to prioritize free cash flow generation in the current depressed oil price environment, both spending and supply levels are expected to decline this year and into 2021. In addition to delayed drilling and completion activity, production curtailments and shut-ins have severely impacted North America’s shale supply in the second and partially third quarters of this year. Even with a significant inventory of drilled and uncompleted wells set to come online next year, the growth in activity and supply is not expected to be restored before 2022.