Recently, ExxonMobil, (NYSE:XOM), and Chevron, (NYSE:CVX) announced their intention to sharply ramp up production in their shale output by about 25% this year. The companies both have a large production base already with XOM having added about 85K BOEPD to their 460K BOEPD total in 2021. CVX is a little behind XOM with around 300K BOEPD, and plans similar growth of about 25% in 2022. If this comes to fruition, it will add another 180-200K BOEPD to the increase in U.S. shale output that the Energy Information Agency-EIA, projects will rise by ~800K BOEPD this year.
As I discussed in a recent OilPrice article this is being driven by fundamentally strong prices and a finite limit to the number of Drilled but Uncompleted wells-DUCs that can be brought online. In that article, I quoted a Rystad article that theorized that Tier I drilling locations had been pulled forward due to low prices at the time. This could presage an unexpected outcome over the next couple of years.
“Five months into 2020 and three months into the downturn and the resulting drilling-activity collapse, we see that operators are increasingly focusing on sweet spots. This is likely to result in Tier 1 acreage making up a record 47% share of this year’s total drilling activity, up from between 36% and 40% in the 2016 to 2019 period.”
So far the larger independents like Occidental Petroleum, (NYSE:OXY) and Pioneer Natural Resources, (NYSE:PXD), and others have not announced major revisions to their capital plans. These plans, referred to as “sustaining capex,” had been formulated to maintain current production or slightly increase it to help stabilize oil prices at current levels north of $80 per barrel. However, the CEOs of two major production companies, ConocoPhillips (NYSE:COP), and OXY was quoted in a Reuters article as acknowledging that shale output will rise sharply above previous projections from a year ago. Given that, it is likely we will hear of upward revisions to previously announced capital budgets for 2022.
In this article, we will look at a couple of near-term scenarios that will likely derive from this shift in strategy. Among them will be the last great American oilfield boom.
Capital always seeks its highest return. That is an almost unquestioned maxim of economics. Shale production, with breakeven costs in the upper $20s for big producers, has reached a point where output must rise, in part from the margins that today’s prices for WTI offer. It would be negligent on the part of oil company managers not to allocate more capex toward pumping more out of the ground in this scenario.
This is going to drive land drilling rig utilization, and rig margins substantially higher as operators look to ramp up their output. Let’s start with the all-encompassing number the EIA projects at about 800K BOEPD by next year, which would push U.S. production back toward the ~13 mm BOEPD seen in late 2019. The EIA Drilling Productivity Report-DPR from January 18th notes a rig-weighted average of ~1135 BOEPD of new oil per rig. Simple math suggests that if that target is reached it will require the support of ~700 additional rigs to obtain. For reference, over the past two years we have added about 400 rigs, from the mid-2020 bottom of 253. (Gray line on chart below).
Data PrimaryVision, Chart by author
One takeaway from the chart is the relatively flat upward trajectory of U.S. rigs in the last couple of years. It is particularly noteworthy in the six months leading up to now, in that the other key metric- oil prices, showed a sharp inflection- 30% higher. This speaks to the capital restraint to which shale producers have tightly hewed. Up to now.
Can we truly see a doubling of the rig count over the next year or so? The incentives are certainly there as we have noted. But, supply chain and staffing limits may have an impact. All companies surveyed have noted that in spite of a new optimism about future prospects, supply chain driven pricing pressures, logistics limitations from trucking shortfalls, as well as the ability to find and train new employees. Halliburton CEO, Jeff Miller commented in some detail on how they were managing these challenges in their Q-4, 2021 quarterly conference call-
“As activity accelerates, the market is seeing tightness related to trucking, labor, sand and other inputs. While we pass these increased costs on to operators, Halliburton has effective solutions that minimize the operational impact of this tightness and provide reliable execution for our customers. As an example, in 2021, we expanded our collaboration with Vorto and now benefit from 5F, the largest integrated transportation platform in the oil and gas industry. This platform has several-thousand drivers, hundreds of carriers, and a chain of asset maintenance yards. It allows us to effectively manage trucking inflation and availability constraints and significantly reduce logistics-related nonproductive time.” Our human resources team and systems effectively mitigate local labor tightness. We recruit nationally and hire, train and manage a commuter workforce that makes up to 80% of our personnel in some areas.”
We have seen similar commentary in reviews of other service and supply companies. One thing that we haven’t discussed yet for the sake of brevity is the decline rate of shale. I discussed this in some detail in an OilPrice article in December. You might give this a read for more background as to shale decline rates could impact drilling.
In summary for this section, the incentive for producers to sharply ramp production is luring them to increase capital budgets to take advantage. If all of this goes as per plan, the result will be a sharp increase in drilling activity in shale plays. Counter-balancing this driver are the logistics and supply chain problems bedeviling industry in general and of course the naturally high decline rate of shale production.
Lack of Tier I locations, Second-order effects-
Other voices are now echoing the concerns I’ve noted about the remaining quality of drillable inventory. An article carried in the Wall Street Journal-WSJ, discussed this dwindling inventory of top-tier locations in a recent article.
“The limited inventory suggests that the era in which U.S. shale companies could quickly flood the world with oil is receding, and that market power is shifting back to other producers, many overseas. Some investors and energy executives said concerns about inventory likely motivated a recent spate of acquisitions and will lead to more consolidation.”
If in fact, this reduced level of premium drilling locations does impact shale output, then the burst of activity I anticipate will not yield the results in production growth desired and anticipated. Does this mean the increase in drilling activity I am projecting will decline as well?
Probably not. The decline rate of shale, the aging of the well inventory, both suggest a renewed drilling push required to sustain, or attempt to increase shale output at higher levels will ultimately fall short of its goal.
We think the increases in output we are seeing now are unsustainable. Companies may shift to lower-tier drilling locations that could not compete for capital in a lower price environment to avoid their being stranded in a downturn. In any event, as these top-tier locations are used, production will fall.
This is bullish for oil prices over the long haul as there is an expectation that shale is a limitless resource that has a direct cause and effect on higher drilling levels. As we have discussed this is likely a misguided notion and fewer future barrels will meet increased demand, pushing prices higher.
All of this is bullish for the companies that drill and produce oil and gas, and as cash flows and margins improve with higher realizations, their share price multiples will go higher as well.
Investors entering the market now will have a chance to participate in an era of sharply higher oilfield activity. The old oilfield prayer of, “just give me one more boom,” is about to come true.
By David Messler for Oilprice.com
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