By David Messler High decline rates, and a falling number of DUCs could incentivize drillers to ramp up drilling in the first half of 2022 • Land drillers have lagged the rest of the recovery, but could already be on the uptick • Drilling contractors and equipment suppliers tilted toward drilling could be set to profit from the ramp-up in activity among E&Ps WTI and Brent proved how closely tied oil prices are to perceptions about the economic recovery over the last couple of weeks. For a time breaking down as much as 20% from their respective highs over the last month, WTI and Brent both bottomed Wednesday, Dec 1st. News that the Omicron variant might not be as lethal as the still dominant Delta version, breathed new life into oil futures and thus far sparking a 10% rebound. As usual, shares find downward momentum easier than the reverse, so we are still clawing back gains made earlier in the month. In this article I will extend the discussion I started in a recent OilPrice article, where I made the argument that U.S. shale producers would not raise capex to increase production significantly in the face of the higher price regime now in place. I do think there is a rationale emerging for a shift toward increased drilling that would require additional capex to maintain output. As the graph farther down the page points out, oil production in the U.S. has been maintained this year by DUC-Drilled but Uncompleted Wells, withdrawal from inventory. As an article carried in Natural Gas Intel notes the reduced upfront capital cost for DUCs has been driving their rapid decline so far this year, but the excess inventory has been worked off and companies will have to resume drilling to maintain production. “However, “drilling activity has severely lagged completion activity,” Freeman noted. For E&Ps, the “thought process is simple.” Completing DUCs requires a “fraction” of the capital spending required to sustain production compared to drilling and completing more wells. That in turn has allowed E&Ps to maintain their capital discipline, grow their free cash flow and improve investor distributions.” Natural Gas Intel In this article we will do a little ciphering to come up with a rig demand to maintain oil output if indeed DUC withdrawals slows. We will also point to a possible beneficiary of this move toward drilling and suggest an entry point, and possible growth led rise in valuation. The next step for shale, Drill Baby-Drill I am going to predict a return to drilling sometime next year. The exact timing isn’t precise as I don’t know exactly the DUC withdrawal tolerance for oil companies. What we know for sure is that DUC withdrawal has been the factor keeping U.S. shale production around 8 mm BOEPD. What I’m expecting to see soon (it could be on Monday) the slope of the green line will flatten, signifying a slowdown in the rate of DUC withdrawal. In past OilPrice articles I’ve discussed the point that shale comes with a fairly high decline rate-40-60% annually, as opposed to conventional reservoirs-6-10% annually. This means shale production is a perpetual motion machine. You have got to keep drilling to replace field declines, or production will drop. Or you can pull DUC’s out of inventory at rate fast enough to stave off the inevitable decline that drilling too few wells will bring. I say stave off, not eliminate as we all know…chickens will come home to roost. If this indeed comes to pass, companies that have been left behind-at least to some degree, should see their fortunes improve. I am thinking of drilling contractors and equipment suppliers tilted toward drilling. Loose math shows a decline of about 2,500 DUC’s since the beginning of the year, or an average of 227 per month. An article in Forbes put out an estimate of 430K BOPD legacy decline rate for shale wells, meaning that new production must exceed that figure to maintain production. That is a little higher than some estimates I’ve made in the past, and may include a correction for the age of the well-inventory. We’ve been adding to production since earlier this year, so we can come up with a quick and dirty guesstimate for how many rigs it would take to replace that production if the pendulum swings to drilling. Over the course of the year shale production has rebounded from about 7-mm BOEPD to the present ~8-mm BOEPD. Roughly 1-mm BOEPD, so on top of legacy decline shown above DUCs have been adding another 100K BOEPD per month in conjunction with the restrained new well drilling. Now let’s agree DUC withdrawal will slow, but not come to a screeching halt. Also factor in that some drilling will be required to rebuild DUC inventory. From the middle of last year to January of this year we dropped a much more modest ~4-500 DUCs, so we will take that as a more realistic average. Roughly 75 per month. Using those numbers we will see about 75-80K BOEPD from DUCs, meaning we have to drill enough wells to replace about 430K + 600K new BOEPD, as a conservative estimate. The EIA tells us that new oil per rig is running at an average of 1,143 BOEPD, or about 658K BOEPD. That doesn’t take into account production from excess DUCs which must have been about 350K BOEPD to get the million BOEPD we’ve gained. Hence if we want to maintain production levels we have presently we need to add about another 250 rigs turning to the right, and probably another 75-100 frac spreads. Your takeaway There’s an old adage about predicting the future that points out predictions are generally wrong, especially when they involve the future. That usually gets a wry chuckle from anyone who’s made a forecast and had it bomb. That said, a prediction of the future is the reason you are reading this article. So now that you’ve read “tomorrow’s paper,” what to do with this information? As I’ve noted in this article land drillers have lagged the rest of the recovery, but could already be on the uptick. One I follow, Nabors Industries, (NYSE: NBR) has rallied 20% from a recent low set in early December. It could have further to go. NBR has broken $120 three times this year on positive momentum from WTI price movements. Analyst coverage is marginal but the few who do cover it have an average estimate of $112 for the stock. The high estimate is $151 per share. With about 15% of the rig market, if my prediction about adding another 250 rigs in 2022 bears out, that would translate to 25-28 for NBR. With rig rates rising to the mid-$20,000’s per day another $80 mm in EBITDA would be added to the balance sheet. NBR is currently selling at 8.76X EBITDA, to maintain that the stock would need to rise into the mid-$120’s, and could be easily carried toward that $151 valuation with positive WTI momentum. The inverse is also certainly true as regards the oil price. NBR is a high beta stock that overreacts to changes in the oil price, so if you’re intrigued by this idea, pick your entry point carefully. For my own risk tolerance, a move below $90 would pique my interest. You can decide for yourself if this rationale and suggestion appeals to you and fits in your own risk profile.