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Quarterly Analysis Highlights Leading Edge Results

2Q 2020 – The E&P Positioning Report has entered a new stage in its evolution to offer more granular insights with the ability to view and filter data on a quarterly basis through the BTU View platform. Previously the report was limited to one-size-fits-all basin maps of breakevens and remaining inventory grids overlaid with ovals indicating operator acreage for a select group of larger operators. With the BTU View platform, users can now filter breakeven results for any combination of public or private operators over any duration, giving users access to the data that meets their specific objectives. With superior mapping and visualizations moved to the online portal, the format of the PDF delivery is changing as well. With this publication, BTU Analytics will now provide a streamlined publication that focuses on what is incremental to the data set, which now includes nearly 80,000 horizontal wells drilled since 2013. The analysis will include an examination of new wells entering the dataset for the first time, changes in basin breakeven estimates based on new wells or new data entering the data set, and a summary of the latest basin-level results by operator for the largest public operators.  

New Content: Summary of New Wells Added

Note (left): Contains horizontal wells with at least one full month of production as of 3/31/2020
Note (right): Contains horizontal wells with at least one full month of production as of 6/30/2020

BTU Analytics adds new horizontal wells in the major shale basins to the economics data set as each well records at least one full month of production data. Data is pulled as of each calendar quarter end and published at the end of the following month. This means that most wells enter the economics data set about one quarter after their first production date.

With the July update 3,021 wells were added to the data set. Of that, 2,016 wells were added that commenced production in 1Q20. No wells from 2Q20 had enough production history for inclusion when data was pulled on June 30th. The second largest vintage added to the July 2020 data set were 611 4Q19 wells, which joined the 1,754 wells from 4Q19 that first appeared in the April 2020 report. Based on the delayed additions of 2Q19 and 3Q19 wells in the April 2020 data set, BTU Analytics expects to add additional wells with first production dating back to 4Q19 over the next six months, mainly in basins with more severe lags in state reported production, such as the Eagle Ford and Permian Basin in Texas.

With data now being displayed on a quarterly basis within this report and on the BTU View, trends in the data are easier to observe and track. Aggregate measures of play or operator performance such as median or average breakeven pricing can be useful guideposts for the overall profitability of US shale, and leading edge results can provide an early look at industry trends if the sample sizes are large enough.

New Content: Changes in Basin Breakeven Estimates

The charts below provide regional summaries of breakeven pricing in both the latest run (July) and the previous run (April). In order to allow for more direct comparability between quarterly data updates, the BTU View platform includes flat price strip pricing assumptions for both oil and natural gas in addition to current strip pricing. The analysis below compares economic runs at fixed WTI and Henry Hub prices of $40/Bbl and $3/MMBtu, respectively. In a similar attempt to stabilize commodity price assumptions through time, NGL prices are calculated based on each purity product’s five-year average relationship to WTI. The breakevens shown here are wellhead values, to eliminate differences in differentials between periods.

Note (left): Assumes $3/MMBtu Henry Hub and five-year average NGL price relationships as percentage of WTI as of 3/31/2020
Note (right): Assumes $3/MMBtu Henry Hub and five-year average NGL price relationships as percentage of WTI as of 6/30/2020

The only 1Q20 data available as of the April run was for three wells in the PRB. With the July run, an additional 52 wells were added to the PRB 1Q20 data set. A closer examination of the relationship of the economic result for the initial wells versus the wells available with the latest results highlights both the opportunity and risks in the use of initial results in a given area.

With the addition of 52 1Q20 PRB wells in the July 2020 data set, the median breakeven for 1Q20 fell to $49.18/bbl from $66.23/bbl in April. Some of the variables considered in estimating breakeven economics include lateral lengths, depths, proppant intensity and well-level production history. A summary table of the economic drivers for the PRB by report date is shown below.

Note: Breakevens assume $3/MMBtu Henry Hub and five-year average NGL price relationships as percentage of WTI as of 6/30/2020

The initial 2020 PRB wells in the data targeted the Turner formation. While Turner wells comprise the majority of 2020 PRB activity in the July 2020 data set, the drivers of breakeven economics vary by horizon, as shown above. The median oil EUR estimates for all horizons came in higher in July than the median estimate based on just the three Turner wells in April, which had the overall effect of lowering the regional median estimate.

Looking at some of the median basin breakeven changes further back in history, Cotton Valley median breakevens for 3Q19 increased from $2.27/MMBtu in the April report to $2.81/MMBtu in the July data set. With the addition of only one well to a nine well sample, it is hard to believe that the median breakeven price increased 24%. However, digging into the economic drivers shows that the 3Q19 wells underperformed EUR estimates made in April.

Note: Breakevens assume $40/Bbl WTI and five-year average NGL price relationships as percentage of WTI as of 6/30/2020

BTU Analytics estimates a well’s EUR using historical production and future production estimates based on historical type curves in that sub-location. EUR estimates made very early in a well’s life will be revised as more, actual production history becomes available. As an example, a single Cotton Valley well that began production in July 2019 is shown below.  

The chart shows gross gas production history that was available at the time of the April 2020 report publication. As mentioned earlier, initial production data from a well is of paramount importance in determining early breakeven estimates, and early estimates chart the course for the production profile with relatively few data points.  Based on three additional months of da
ta, the gross gas EUR estimate for this well diminished, driving a revision from 6.29 Bcf in the April report to 4.26 Bcf in the July data set. This revision raised the breakeven estimate for this well from $2.24/MMBtu to $2.95/MMBtu.  BTU Analytics monitors revisions like this one to determine whether future adjustments to decline profiles should be made based on any pattern in estimate errors.

New Content: Summary Results by Operator by Play Table

This report includes a breakdown of trailing 12-month average breakevens by operator by basin to summarize data that can be pulled through BTU View.  The format allows for overall portfolio analysis for diversified operators as well as comparing basin-level performance to other prominent peers.

Top Operator Summary – TTM Average WTI and Henry Hub Breakevens

Note: Assumes futures strip as of 6/30/2020. 5-yr WTI avg $42.36/Bbl. 5-yr Henry Hub avg $2.42/MMBtu.
Includes wells with first production dates from 7/1/2019 through 6/30/2020.

Coming Soon: More Timely Data for Decision Making

BTU Analytics recognizes that a lot can change between the quarterly updates currently being made to the BTU View economics data set. In order to increase transparency and deliver additional leading edge economic data points, BTU Analytics plans to incorporate a framework for updating the economics data set on a monthly basis by the end of 2020.

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