How High Can US Shale Production Climb

By David Messler of OilPrice.com

The shale drilling boom that ended in March of 2020, as the full effects of the pandemic hit the economy, contributed to a surplus of oil in storage that kept prices down.

Richly supplied both in the U.S. and globally, the market took the spot delivery prices down to unprecedented levels. In April 2020, the spot price actually went negative for the first time ever.

As the economy recovered, inventory levels declined, bottoming out in March of this year, at about 415 mm bbls across all PADD districts.

Not only did storage decline, but U.S. production declined sharply in this period as the low prices made much of it uneconomic to drill. Rigs were stacked like cordwood in the outskirts of Midland, with the active rig count falling to 252 by June 2020. As we moved into the third quarter, WTI prices surpassed $40 and rigs began to go back to work. Over the course of 2021/22, another 500+ rigs were added with about 40% of that coming this year as drillers moved to take advantage of still low rig rates and WTI prices in the $80-$120 range. A combination that doesn’t often present itself.

Russia’s invasion of Ukraine sent oil above $100 per barrel, causing gasoline and diesel prices to soar and consumers to suffer a lot of pain at the pump. At the same time, the recovering economy and the loosening of Covid restrictions created a surge in travel, both on the open road and in the air. There has been an expectation from regulators and politicians that oil companies would take their increased revenues and hire more rigs to bring down prices. A practice that would have fit their former model of compound annual growth rate – CAGR, using borrowed capital, and nearly brought many of them to ruin in the years leading up to 2020. 

Instead, the shale drillers, now wiser, have adopted a practice of capital restraint that has the objective of maintaining production at current levels with a slight bias to growth. Attending the JP Morgan Energy Conference in Houston last June, Pioneer Natural Resources, (NYSE:PXD) CEO was quoted addressing this issue in an Oil and Gas Journal article.

“We’re [Pioneer] only going to grow 5% per year; I’ve been asked that in 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 increase production. “We said no to them also,” Sheffield continued. “We’re trying to get them to understand the model and the reasons the model changed,” he said, in discussing a past model of boom-bust cycles in which the oil and gas industry responded by ramping up production that ended in oversupply.”

Other CEOs have made similar commentary, stressing that their priority for capital allocation is not production growth, but the return of capital to shareholders. Another large 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 capital allocation with a growth target for 2022 of ~5%.

What hasn’t gotten a lot of attention is an external, natural limit to growth in shale production. Shale drillers in the lean times chose to develop their best locations to ensure payouts that would return more revenue than they cost to drill. (I discussed this trend in an earlier Oilprice article last May.) The industry calls these Tier I locations. The linked Rystad article notes the following in regard to remaining Tier I locations.

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

While a significant amount of Tier I acreage remains, there are signs the wells now being developed contained a higher mix of lower-tier rock. The chart below, compiled from the EIA-DPR’s published data reveals a troubling trend in overall shale activity, with a particular focus on the Permian basin. The Permian basin contributes over half of U.S. shale production.

The DPR monthly report makes a simple calculation of individual well productivity per rig by dividing the production for that month (shown two months in arrears), by the number of active rigs. The data is revelatory in the following respects.

The blue line, representing all eight basins tabulated in the report, trends down over the last year, while the total rig count as reported by Baker Hughes is rising sharply. The orange line, representing the Permian basin, follows the same trajectory, with daily production declining per well by about 120 bbl per day over this time.

What is additionally noteworthy about this data is while production is declining as rigs are added – something that is a little counter-intuitive – the rates of monthly DUC-Drilled but Uncompleted wells and withdrawals are also declining. This is suggestive that the daily production rate per rig, already on the downslope, was boosted artificially by operators fracking an already drilled well to turn it inline. 

I next turned to the EIA-914, the monthly report of all producing states put out by the agency. The 914 report also contains data 2-months in arrears, and in this case shows the data through May. I took all states producing more than 400K BOEPD and tracked their output.

Note-the Total U.S. line is plotted on the right-hand Y axis

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 can skew the overall data temporarily, with the same being true for onshore production in wintertime.

Takeaway

We may yet add another 800K BOEPD by the end of next year as the EIA Short Term Energy Outlook-STEO suggests we may. You never want to say never until time passes. The data I’ve reviewed says otherwise, however.

What this means for oil prices is yet unclear in the short term as for the last six weeks concerns about a possible recession have trimmed roughly $20 per barrel from the price of WTI and Brent. Longer term, if this trend toward lower well productivity bears out, we could see a sharp reversal higher, as shale output declines.

Many analyst firms have kept a YE-2022 exit price target above current levels, with Goldman Sachs the most bullish of all at $135 for Brent. If all of these things come together consumers could be in for more pain in the pocketbook, as tight supplies result in higher prices.