There is a rather gleeful assumption in government circles that shale production can be increased at will. This assumption is about to be tested as the U.S. shale drilling and fracking industry attempts to respond to direct pleas and demands from lawmakers, executives in the administrative branch and even from the president himself to invest more capital in increasing production.
It is happening, but at a level and pace that will be insufficient to significantly boost production. In fact, data from the most recent release of the Energy Information Agency-DPR Drilling Productivity Report indicates that trouble may lie ahead. As the graph drawn from the EIA-DPR data reveals, rig counts are steadily increasing, but production from the eight major shale basins has leveled off and, as of February 22, actually declined slightly. If the May edition of the DPR confirms this trend, then it will require a drastic reassessment of what will be expected from shale going forward.
One obvious cause of the decline is not directly related to the number of rigs, but to the decline in drilled but uncompleted-DUCs, as wells are turned into production. Over the past two years, operators have reduced DUC inventory from ~8,500 to ~4,200.
A year ago in a Article on oil prices, I had predicted that this point would happen. It has now come as operators have dramatically reduced the DUC withdrawal that has been maintaining and increasing production over the past two years. There are several reasons for this situation and the main ones will be discussed in the rest of this article.
Forecast of the number of platforms
Physicist Niels Bohr once said, “This prediction is difficult, especially about the future.” Anyone who has made a sales forecast can understand this ironic witticism. Recently I attended an industry conference, the American Association of Drilling Engineers-AADE, where the keynote speaker – Richard Spears, industry analyst and consultant, spoke about a key difficulty in forecast with regard to the estimate of the probable number of drilling rigs at the end of the year. His argument was that events happen that make earlier forecasts ridiculous. His example was the invasion of Ukraine, which was not on anyone’s radar…until it happened, and which immediately rendered all predictions up to that point obsolete. Almost ridiculously.
He then polled the room as to where we thought the number of land rigs would end for 2022. He threw in numbers starting with 800, about a hundred more than where we are now, and we answered when it reached the number that corresponded to our personal conviction. Virtually all the hands rose to 800, about half fell to 900, the other half to 1000 and only a few to 1100. One or two hands stayed up at 1200 and it stopped there . He then gave us his number, 800. This surprised me as I was one of the 1100 hands. His rationale for this figure did not surprise me, as it involved capital restrictions, lack of funding and logistical impacts that cause inflation in the oilfield. All the things I’ve discussed before Articles on oil prices.
A article in the Wall Street Journal put a personal spin on this, as they cited a small independent driller’s frustration at being able to obtain the materials needed.
“If someone comes in and puts a pile of money on the table and says, ‘Drill me a well next week,’ that’s not going to happen,” said Jamie Small, president of the oil producer backed by private funds Element Petroleum. III. “You just can’t get the necessary items to do it.”
Take this operator’s frustration and multiply it by dozens of other smaller independent oil operators who drill about half of the wells drilled each year, and you can see serious trouble is brewing.
Oil companies revised their playbook after nearly going bankrupt after March 2020. As oil prices rose, these companies shifted their capital allocation from growth to maintenance investments, freeing up huge sums to reduce debt, reward long-suffering shareholders with dividends, and buy back their shares – which were at ridiculously low levels after the pandemic. All of this is pretty well known now. What is not so well understood is that despite some very public comments of the big players, ExxonMobil, (NYSE:XOM) and Chevron, (NYSE:CVX) to sharply increase production, most companies are sticking closely to previously announced capital budgets. This could have profound implications for future production estimates.
Access to finance
the large institutions’ reluctance to invest in oil and gas is well known, at least as far as the big players operating the leases are concerned. What I didn’t realize was how service companies are affected by this mindset. Note this quote from Schlumberger’s press release, (NYSE:SLB)-
“First quarter operating cash was $131 million, including a first quarter of building up working capital above the usual level, ahead of expected growth for the year. We expect free cash flow generation to accelerate throughout the year, in line with our historical trend, and still expect a double-digit free cash flow margin on an annual basis.
SLB public repositories
In the first quarter, they burned half a billion dollars in cash, likely supporting the build-up of working capital for ongoing project mobilization.
SLB public repositories
SLB is not alone. Halliburton, (NYSE:HAL) burned nearly $1 billion in cash in the first quarter, likely for the same reasons as its biggest rival.
Halliburton Public Repositories
If big players like HAL and SLB are shut out of traditional funding, you can imagine the difficulty tier 1 or private companies face.
A final point here that Spears made is that service costs are always below replacement cost, and that’s going to have to change soon. He commented that based on his research with drilling contractors, daily rates for high specification rigs will be around $40,000/per day by the end of 2022. About double current levels . Other service companies will do the same.
One of the points he made here is that the oil companies may have to become the bank for the service companies. It’s not a comfortable position for them, but as you can see, service provider cash burn cannot last. At this rate, cash balances will be depleted before the impact of rising rates hits the balance sheet. In a way, these are great problems to have. HAL and SLB are tasked with doing more, which will impact cash flow and earnings. The problem is that management hasn’t squarely addressed profitability. All utilities have pledged to raise prices to improve profitability and cash generation. Spears noted that this is on the horizon with private companies and hopefully soon.
Logistics, supply chain and inflation
The pandemic has disrupted the flow of goods from traditional manufacturing points. The war in Ukraine has profoundly exacerbated this in ways we are only just beginning to discover. As an example, Richard cited the bit company he serves as a board member. The drill body is cast and cobalt is used to strengthen it. The widespread and growing manufacture of batteries for electric vehicles has caused disruptions in the supply and cost of cobalt.
His argument was that the drill bit manufacturer is very low on the cobalt supplier allocation curve and has no leverage when it comes to negotiating prices.
Take this factoid and extend it across the entire oilfield supply chain. The costs disappear and will soon result in a restriction of the availability of services. He also cited an exponential increase in the cost of frac gear to repair worn fluid ends on pumps.
Your takeaway meals
These are growing pains in my book. I’m not quite ready to agree with Richard on the US land drilling output rate for 2022 at 800, but it’s probably well below my estimate of 1,100. The bigger point is that 800 National platforms are approaching a very healthy market for services, and in this oil price regime, this growth should continue into next year.
The overall implication for service providers is a higher oil price regime for longer, leading to a robust market, as Big Red and Big Blue demonstrated in their Q-1 reports. For me, cash burn will slow as prices adjust and working capital is supplemented with cash flow. They should be bought near current levels on any weakness.
For oil production from shale basins in general, the forecasts are not as clear cut. As noted in the Oilprice article I referenced above, the quality of the remaining undrilled shale acreage raises concerns about its ability to provide the amount of production provided by Tier I acreage.
“One of the questions that often comes up is what will happen when the Tier I acreage is excavated. There are estimates that this could happen within the next decade. longevity of Level I shale in years at current drilling rates.
Why U.S. Shale Production Remains Stubbornly High, OilPrice, March 10and2021
What is clear is that the government’s flippant faith that shale production can easily increase is misplaced. A combination of natural limitations, logistics, inflation and human impacts are taking their toll, and the effects will become more evident as the year progresses.
By David Messler for Oilprice.com
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