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2020 Shut-Ins: Looking Past One-Time Events in Crude; Operators Strategically Curtailing Production to Optimize Returns in Gas

3Q 2020 – The year 2020 has been anything other than business as usual in the US E&P sector. Macroeconomic shocks upended the near-term outlook for oil and natural gas, and producers have responded. Curtailments and shut-ins occurred in both oil and gas-focused plays. However, these actions are expected to be infrequent occurrences in oil plays, while curtailments in gas may become a strategic tool of more operators in years ahead.

Crude Oil

Due to the extreme volatility observed in crude pricing this year, many producers in liquids-focused basins made the difficult decision to curtail their existing production as demand rapidly fell and storage capacity filled. The duration and severity of the shut-ins varied by producer, as did their strategy in determining which wells to curtail production from.
Most of the curtailed production returned to the market, but lags in state production reporting mean that the last reported production for many wells is not indicative of that well’s potential, as it represents a curtailed volume. This presents a problem. BTU’s well-level production forecasting methodology, which models future production based on recently observed actual well performance, will in some cases with limited production history, calculate estimated ultimate recovery (EUR) values that can be meaningfully lower than previous estimates. The model could also give new wells that began producing during the period of curtailments lower expected EURs.
BTU Analytics’ approach to the analysis of well economics is based upon a foundational assumption that future well performance and economic potential should be rooted in the proof of concept that the population of recent well results provides. BTU Analytics calculates breakeven estimates to be an indicator of expected performance for future wells and to determine where future activity is likely to occur. If the methodology for modeling recent wells gives an inaccurate portrayal of future economic potential, the methodology must be revisited. In order to defend the integrity of this analysis, BTU Analytics has elected to ignore shut-in impacts to breakevens in liquids-focused plays for wells producing prior to April 2020 at this time.
BTU Analytics does expect the methodology adjustment to be temporary, and that the previous methodology can be reverted to once another quarter of well production history shows a recovery in well performance following the shut-ins.
Temporary Methodology Revision for Crude Oil Plays Due to Shut-Ins
In the days and weeks following the escalation of the lockdown measures to slow the spread of Covid-19, many producers elected to curtail wells early in their lives that were modeled to still have significant future production remaining to be sold. Wells turned to sale in 2019 and 1Q 2020 accounted for a meaningful share of production, so in many cases, volumes from wells of this vintage plummeted in 2Q 2020 far more severely than wells of older vintages.

Note: Uses historical well costs, breakeven estimates are wellhead pricing. Henry Hub strip as of 9/30/2020
The chart above illustrates how shut-ins could have impacted the outcome of the analysis if the methodology would not have been altered. The chart shows a Permian Basin well that started producing in April 2020 and saw production plunge with the spring shut-ins in 2Q 2020, which drastically lowered the transition into its modeled production declines given the limited production data available post-shut-in as of October 2020. The drop in the modeled future production line using shut-in production data is due to BTU’s well-level forecasting methodology, which models future production based on several points in recent history, not just the final month of reported production data. The shut-in’s impact on a young well is severe and very recent, resulting in drastically lower modeled PDP.
For this quarter’s economics data update, BTU Analytics relied on a second set of calculated production curves in liquids-focused plays to negate the impact of shut-ins on estimated ultimate recovery and breakeven prices. These estimates ignore production reported in April and beyond and instead begin projection of future production beginning in April 2020. By temporarily changing methodology, the oil EUR for this well was not revised downward by 393,000 barrels, resulting in a breakeven estimate of $37.42 instead of a potentially misleading $51.06 using shut-in skewed PDP estimates.

Note: Uses historical well costs, breakeven estimates are wellhead pricing. Henry Hub strip as of 9/30/2020. Expected 4Q 2020 production scenario estimates the production curve if post-shut-in production stabilizes PDP curve near pre-shut-in estimate
While the brief shut-in production events should ultimately impact affected wells’ EURs and breakeven estimates, the chart above shows how minimal the changes to EURs and breakeven pricing might be when the additional state-reported production becomes available.
Basin-Level Impacts
Three key basins, the Permian, Eagle Ford, and Bakken accounted for 62% of Lower 48 horizontal wells turned to sale in 2019, with the Permian accounting for 38% of the total Lower 48 activity alone. By ignoring the impacts of spring shut-ins in liquids-focused plays, over half of all 2019 to present wells in each of these basins avoided a negative EUR revision, meaning their modeled PDP curves using full production history available would have been disproportionately skewed downward in the long-term based on recent shut-ins.

Note: Operators chosen based on the percentage of wells impacted by methodology adjustment for operators with more than 50 wells turned to sale since 2019. Uses historical well costs, breakeven estimates are wellhead pricing. Henry Hub strip as of 9/30/2020
If BTU Analytics would not have altered methodology this quarter, 55% of Permian Basin wells turned to sale from 2019 to present would have been modeled with a lower oil EUR than pre-shut-in production estimates dictate. The five operators with the highest percentage of wells from 2019 to present impacted by the change in methodology were Sable Permian Resources, WPX Energy, CrownQuest Operating, QEP Resources, and Shell. The severity of the avoided revisions in EUR (dark blue) varied by operator. As a point of reference, the teal bars in the chart represent EUR revisions for 2019 to present wells in the data published in April 2020 versus the EUR projections for the same wells in the next quarter (July 2020). Movements in EUR projections are generally due to differences in operator-specific decline profiles, as discussed in the 3Q 2019 E&P Positioning Report.

Note: Operators chosen based on the percentage of wells impacted by methodology adjustment for operators with more than 50 wells turned to sale since 2019. Uses historical well costs, breakeven estimates are wellhead pricing. Henry Hub strip as of 9/30/2020
Ignoring shut-ins in the Eagle Ford resulted in not revising lower EUR projections for 62% of Eagle Ford wells turned to sale from 2019 to present. Unlike other basins where the impacts didn’t show any geographic concentration, the wells impacted by this judgment were concentrated in the oiler Eastern Eagle Ford.

Note: Operators chosen based on the percentage of wells impacted by methodology adjustment for operators with more than 50 wells turned to sale since 2019. Uses historical well costs, breakeven estimates are wellhead pricing. Henry Hub strip as of 9/30/2020
The Bakken contained a similar proportion of 2019 to 1Q 2020 wells that would have experienced lower EURs if shut-in production had been incorporated at 61% of total wells brought online since 2019. Continental Resources, a prominent operator in the Bakken that announced material shut-ins on April 7, 2020,  reflected the highest portion of impacted wells from 2019 to present at 87%. The severity of its alleviated average oil EUR impact is only matched by the Slawson Operating Company among the top five impacted operators. The Bakken’s average breakeven already teeters close to the $50 mark, proving difficult to support activity near today’s $40 levels. If BTU Analytics incorporated shut-in-skewed recent production in the Bakken breakeven estimates, the resulting estimated inventory runway would not support activity for the next several years, misrepresenting the quality of acreage in the basin as well as E&P companies’ operational execution.
Given the weight the Permian, Eagle Ford, and Bakken hold in terms of US liquids-directed shale activity, the impacts of shut-ins on breakevens and EURs are particularly representative of the US shale industry trends. The production impacts of shut-ins were both acute and severe, leaving recently turned to sale wells with vastly different production profiles without having significant post-shut-in production data available. As such, breakeven estimates carried forward throughout BTU Analytics’ product suite, including our 30-year Long Term Gas Outlook, would be disproportionately impacted by the near-term impacts of shut-ins. Until additional production data becomes available to capture realistic EURs and breakeven estimates for wells turned in line from 2019 to 1Q 2020, representative economics negating shut-ins impacts serve as better indicators of economic performance for future activity. BTU Analytics expects EUR and breakevens will not be revised significantly next quarter when additional production data after shut-ins are available.
Natural Gas
In Southwest Appalachia, two larger independent operators, EQT and CNX Resources announced strategic temporary curtailments in shoulder months as seasonal commodity price relationships provided the opportunity to add value by shifting production to future periods. The seasonality of natural gas demand and the lack of seasonality in supply means that pricing generally rises and falls with the seasons. The impact on producer realizations can be even more extreme when infrastructure constraints are layered on, pressuring basis differentials in shoulder seasons. By combining these dynamics with the fact that the economic value of production from unconventional horizontal wells is so early-life weighted due to the production profile and time value of money, the financial incentives appear to align for timing production to capture the highest possible pricing. This suggests that more producers could begin employing curtailments as a strategic tool in the future.
The graphic below illustrates the opportunity. The production and cost assumptions come from a well in the Southwest Appalachia region. Assuming it came online in September 2020 (using strip pricing as of August) provides an internal rate of return (IRR) estimate of 20%. Assuming that same August strip price, but assuming that the operator chose to defer producing that well until November when prices rise considerably (implying 2 months of deferred production) increases the IRR to 22%. While the increase is modest, it demonstrates just how producers can use short term curtailments or delays in bringing wells online to boost returns.

Note: Cash flows are estimated revenues less operating costs of wells. Assumes strip pricing as of 8/2020 and BTU Analytics forecasted basis differentials for Dominion South. TIL = “Turned in Line”
Unlike the spring shut-ins in crude plays, the incentive to optimize gas production seasonally isn’t likely to be a one-time event. For that reason, BTU is not making any changes to the methodology for projecting EURs or calculating economics in natural gas-focused plays at this time. For wells that enter the data set and are significantly curtailed, estimated economics and EURs will be impacted. 

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