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EIA Drilling Productivity Report Misleading the Market?

Recent headlines from journalists and industry veterans alike have pointed to the latest EIA Drilling Productivity Report (DPR) as a sign that US oil production growth rates are slowing and that the growth in Permian productivity has stalled out. (See chart below).  BTU Analytics would contend that those hoping that Permian productivity has hit a peak and thus US oil production forecasts are overblown are deceiving themselves.

Each month, the EIA estimates the productivity of the US shale rig fleet for seven major shale producing areas including the Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian, and Utica. Let’s begin by briefly reviewing the EIA Drilling Productivity Report model methodology using a numerical example in parenthesis.

First, the EIA estimates legacy gas production changes by comparing production between two consecutive months. In the first month, EIA sums the production from all producing wells in that period (100 B/d) and then in the second month sums the production from the same group of wells as the first month (75 B/d). The difference in production between month 1 (100 B/d) and month 2 for the same wells (75 B/d) is the legacy production change (-25 B/d). In a perfect world, the difference between month 1 and month 2 for the same wells would nearly always highlight a decline in the base production because reservoir pressures should decline between month 1 and month 2 reducing the total output from the wells.

The next step toward calculating rig productivity is to subtract the legacy production (75 B/d) from total production in month 2 (200 B/d). The resulting output should be the new production (125 B/d) added by producers in month 2. The EIA Drilling Productivity Report model then divides the new production (125 B/d) by the total number of rigs operating two months ago in the basin (25 active rigs) to calculate productivity per rig (125 / 25 ) = 5 B/d per active rig.

Month 1 Total Production = 100 B/d

Production from Legacy Wells in Month 2 = 75 B/d

Month 2 Total Production = 200 B/d

New Production Added = 200 – 75 = 125 B/d

Total Active Rigs 2 Months Prior = 25

Productivity Per Rig = New Production Added / Total Active Rigs =

125 / 25 = 5 Barrels of oil per rig

There are several potential flaws with modeling rig productivity utilizing this approach. The first flaw is that it assumes all new production in period 2 originated from rigs active just two months prior.  It’s no secret at this point that the industry has a tremendous ability to add rigs quickly to a region, but completion crews often fail to keep pace with producers in the basin.  From 2009-2015, operators in the Marcellus and Utica outstripped the ability of infrastructure and completion crews to keep pace with drilling activity, leading to a peak of nearly 1,600 wells in excess backlog, and oil plays have been no different. The price crash in 2015 led operators to defer completions across all of the major oil producing areas, leading to an excess backlog that peaked in 2016 at over 2,000 wells in the Eagle Ford, Permian, Bakken, and Niobrara.

Going back to the example above with 25 rigs running, what happens to rig productivity if producers are only completing 80% of the wells they are drilling in that period? From the EIA Drilling Productivity Report model methodology, the rig productivity would still be 5 barrels per rig, but effectively only 20 rigs contributed production in period 2 since 20% of the wells were deferred to a future period. If we account for the fact that producers deferred 20% of the wells drilled and divide the new production (125) by 20 rigs (25 x 80%), then the rig productivity increases to 6.25 barrels per rig, or 25% higher than the estimate EIA would have of 5 barrels per rig. This also means that the 5 rigs that did not contribute production in period 2 have built a backlog of wells capable of adding an additional 31.25 barrels of production per day in a future period.  The above example assumes that operators deferred completions to a future period, but the inverse can also be true. Rig productivity in period 2 could be overstated if operators deferred completions from an earlier period into period 2 giving the rigs active today an artificial uplift from work done in an earlier period.

Now that we have worked through EIA Drilling Productivity Report methodology with a simplified example, let’s return to the fact that the EIA Drilling Productivity report shows that Permian rig productivity peaked in August 2016 at 707 barrels per rig and has declined to an estimated 597 barrels per rig.

The above chart adds BTU Analytics’ estimates of wells drilled and wells completed for the Permian basin as well as the EIA’s estimate for rig productivity and active rigs. The peak in rig productivity in August coincides with the bottom in the total number of rigs active in the basin. However, completion activity did not follow active rigs to new lows in the summer of 2016 but actually began to increase as producers responded to higher oil prices that had risen from a low of $30.44 per barrel in February 2016 to as high as $48.59 in June 2016, which was just prior to the “peak” in rig productivity.

Since August of 2016, producers have added nearly 200 rigs to the Permian basin, of which 95% are drilling horizontal wells. While producers have continuously added rigs, completion crews have failed to keep up. As of July 2017, BTU Analytics estimates the fleet drilled 375 horizontal wells but only turned to sales approximately 250 wells, reducing the effectiveness of the rig count by 33%. Adjusting the rig productivity for July by the effective rig count (607 / 67%) indicates that rigs are contributing more than 900 barrels per rig, nearly 30% above the EIA peak in productivity in August 2016.

Rig productivity in 2017 likely only gets better if the initial trends in 2017 continue. Operators are pushing towards longer laterals across the board. So far, only Delaware Texas has yet to see a bump in overall lateral lengths (Note: Chart only includes wells with reported production data as of July 2017).

Not only are lateral lengths getting longer for producers in the Permian Basin, but new completion designs utilizing more proppant per lateral foot are contributing to higher initial production rates. The graphic below shows the 30-day average initial production rate normalized for 1,000 feet of lateral.  Despite wells being completed in 2017 in Delaware Texas not being longer than the wells in 2016, the average initial production per 1,000 feet of lateral has increased 54%, and wells in Central Midland have seen IP rates per 1,000 feet of lateral double.

As completion crews race to keep up with drilling rigs throughout 2017, be wary of analysis showing declining productivity.  To follow these developments in coming months, subscribe to the BTU Analytics’ Oil Market Outlook or follow our Permian production forecast in our Upstream Outlook.

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Anthony (Tony) Scott has built an in-depth understanding of the North American energy market by providing investment advisory services and leading teams of analysts focused on the North American energy complex for over 15 years. Mr. Scott cofounded BTU Analytics in 2014 as a boutique consulting firm focused on North American Energy markets. BTU Analytics grew into providing premier research and data services for the energy market and was acquired by FactSet Research Systems in July 2021. Mr. Scott currently is the VP of Energy Analysis for FactSet focused on developing their deep sector product offerings in Energy markets.

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