Shale Production

How high can US shale production go? |

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The shale drilling boom that ended in March 2020, when the full effects of the pandemic hit the economy, contributed to a surplus of stored oil that kept prices low. Richly stocked both in the US and globally, the market pushed down spot delivery prices to unprecedented levels. In April 2020, the spot price was negative for the first time.

As the economy recovered, inventory levels declined and bottomed out in March this year at around 415mm bbls across all PADD districts.

Not only did storage decline, but US production fell sharply in this period, as low prices made much of the drilling unprofitable. Rigs were stacked like firewood on the outskirts of Midland, with the number of active rigs falling to 252 in June 2020. As we moved into the third quarter, WTI prices topped $40 and rigs started to come back online . Over the course of 2021/22, more than 500 rigs were added, with roughly 40% arriving this year, as drillers moved to take advantage of still-low rig fees and WTI prices in the $20 range. 80-$120. A combination that doesn’t come around often.

The Russian invasion of Ukraine pushed oil above $100 a barrel, sending gasoline and diesel prices skyrocketing and putting consumers in a lot of pain at the pump. At the same time, the recovery of the economy and the easing of Covid restrictions created an increase in travel, both by road and by air. There has been an expectation from regulators and politicians than the oil companies it would take your increased income and hire more platforms to lower prices. A practice that would have fit into their previous model of compound annual growth rate – CAGR, using borrowed capital, and nearly bankrupted many of them in the years leading up to 2020.

Instead, wiser shale drillers have adopted a capital-constraining practice that aims to keep output at current levels with a slight bias toward growth. While attending the JP Morgan Energy Conference in Houston last June, the CEO of Pioneer Natural Resources, (NYSE:PXD) was quoted addressing this topic in a Oil and Gas Magazine Article.

“Were [Pioneer] it will only grow 5% per year; I’ve been asked that at every meeting today,” Sheffield told attendees at the June 22 event. “We’re not going to grow 7, 8, 9, 10, 12%,” he said, noting that the company told the Biden administration the same thing when asked to ramp up production. “We also told them no,” Sheffield. “We’re trying to get them to understand the model and the reasons why the model changed,” he said, speaking about an earlier model of boom-and-bust cycles in which the oil and gas industry responded by increasing production that ended in oversupply.”

Other CEOs have made similar comments, noting that their priority for capital allocation is not production growth, but return of capital to shareholders. Another major shale driller, Devon Energy, (NYSE:DVN) has made the same commitment. Devon CEO Rick Muncrief noted in a Bloomberg Interview that the company would continue to be disciplined in allocating capital with a 2022 growth target of ~5%.

What has not attracted much attention is an external and natural limit to the growth of shale production. Shale drillers in hard times chose to develop their best locations to secure payouts that would generate more revenue than it cost to drill. (I discussed this trend in a previous article.) Oil price article last May.) The industry calls these Tier I locations. The linked article from Rystad notes the following regarding the remaining Tier I locations.

“Taken together, the size of the inventory corresponds to 18-25 years of drilling at the rate expected in 2020. If Tier 1 activity returns to the record level of 2019, then we may have six to eight years of drilling capacity at Eagle. Ford and Bakken, and 11-15 years in DJ Basin and Permian. In the Permian Basin, the total size of the remaining Tier 1 inventory is about 33,000 locations, assuming no change in current well separation strategies.”


While a significant number of Tier I acres remain, there are indications that the pits now being developed contain a higher mix of lower level rock. The graph below, compiled from published EIA-DPR data, reveals a worrying trend in overall shale activity, with a particular focus on the Permian Basin. The Permian Basin contributes more than half of US shale production.

DPR’s monthly report makes a simple calculation of individual well productivity per rig by dividing that month’s production (shown two months out of date) by the number of active rigs. The data is revealing in the following aspects.

The blue line, representing the eight basins tabulated in the report, shows a downward trend over the past year, while the total rig count reported by Baker Hughes is going up sharply. The orange line, representing the Permian Basin, follows the same trajectory, with daily production per well declining by approximately 120 bbl per day during this time.

What’s also noteworthy about this data is that while production declines as rigs are added, which is a bit counter-intuitive, DUC-Wells drilled but not completed and withdrawals are also declining. This suggests that the already declining daily production rate per rig was artificially boosted by operators fracking an already drilled well to bring it online.

Next, I turned to the EIA-914, the monthly report of all producing states published by the agency. The 914 report also contains data that is 2 months behind and, in this case, shows data through May. I took all the states that produce more than 400,000 BOEPDs and tracked their production.

Note that the US Total line is plotted on the Y-axis to the right

What it shows is that, across all key basins, production has been relatively flat for most of the past year, and in particular for 2022. Since the Gulf of Mexico is included in this total, there are some weather anomalies that may skew the overall data temporarily. The same goes for production on land in winter.

your takeaway

We can still add another 800K BOEPD by the end of next year as the EIA-STEO Short Term Energy Outlook suggests that we can. You’ll never want to say never until time passes. However, the data I have reviewed says otherwise.

What this means for oil prices is still unclear in the short term, as over the past six weeks concerns about a potential recession have shaved roughly $20 a barrel off the price of WTI and Brent. In the longer term, if this trend towards lower well productivity is confirmed, we could see a strong reversal to the upside, as shale production declines.

A lots of analyst firms have maintained an exit price target for YE-2022 above current levels, with Goldman Sachs being the most bullish of all at $135 for Brent. If all these things come together, consumers could suffer more in their pockets, as supply shortages result in higher prices.

By David Messler for

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