DEP Random Items: Our Sunday night note comes one day early as tomorrow we’ll be goofing off at the Texans game and we don’t want any potential (probable) overindulgence to lead to a distribution error tomorrow evening.  Next, a friendly reminder (and plea) to loyal readers who wish to go to the Permian BBQ to please register if you haven’t already done so.  We have just over 800 registered attendees, but there are still a number of cooking teams, judges and sponsors who have yet to register a single employee.  We can email you the registration link if you lost it.  Finally, the DEP research team has recovered from COVID, but due to this damn illness, we lost our European vacation last week and the wife is still ticked.  To make up for it, we instead head to Kilgore for an East Texas husband/wife oilfield tour on September 22-23rd.  If you are in the Kilgore area and open to visit, let us know.

 

E&P Activity Survey:  Last week we published our U.S. land rig forecast which calls for a ~100 rig count increase from ~495 rigs as of last Friday to around ~600 rigs by YE’22.  Our model assumes gains largely occur during the Q4’21 through Q2’22 timeframe.  Our published estimate was derived from discussions with land drilling contacts, as well as impressions from E&P commentary during Q2 earnings season as well as our gut.  However, to cross-check our forecast, we reached out to E&P contacts this week, inquiring about their 2022 drilling and completion plans.  The confidential survey included feedback from 48 E&P companies who are today collectively running 249 drilling rigs and 107 frac crews.  We provide takeaways from these discussions below, but first we highlight several important caveats.

  1. Most companies have not finalized a 2022 budget, so feedback from this week might not be the Gospel as budgets should be finalized over the next 2-3 months.  While companies do not necessarily intend to deviate from the message conveyed to us, many concede changes could develop subject to market conditions.

  1. Private companies specifically acknowledge more flexibility vis-à-vis capex spending vs. their public peers. Many contend an upwards activity bias should commodity prices flex higher, but the current activity outlook provided to us assumes the forward curve remains intact.  Publics, meanwhile, claim the budget is the budget so once it is set, then 2022 will be locked in.

  1. Our survey included feedback from 48 E&P contacts, a sizeable number.  However, these companies represent only 50% of the active U.S. rig count (per BKR) and ~52% of the estimated U.S. working frac crew count.  Therefore, our extrapolations of this data, which we make, are not without risk.

  1. Notwithstanding the aforementioned caveat, we note our discussions were with decision makers.  Therefore, our contacts have influence, so their tone matters.  Moreover, these contacts would be aware of potential spending plans, even if initial drafts.  Consequently, we put weight on their observations.  Further, we have no reason to believe the companies would provide us with an erroneous outlook, but we know some views are still “best guesses” at this point.

  1. We expect to update with at least another 5 E&P companies this week, so we will update our query totals again next Sunday evening.

Summary:  Our respondents expect a collective rig count increase of 43 rigs.  This is a ~17% increase from their rig count today.  Additionally, these companies collectively foresee an increase of 10 frac spreads, a 9% improvement from today.  Extrapolating this data to the broader U.S. market would imply an increase of ~80-90 rigs with an increase of ~20 frac crews.  Our gut leads us to believe an upwards bias to these estimates exists given the strength of both oil and natural gas prices.  Gut feelings aside, however, the capital discipline theme permeates the narrative with BOTH public and private E&P contacts.  For reference, we asked our contacts for both current rig and frac crew counts today.  We then inquired where these counts would migrate to next year. We did not inquire about 2023 or beyond because no one has a clue.  Importantly, during our discussions, many E&P companies offered their respective views on service costs and other factors influencing the capital budgeting discussion.

The following are key takeaways:

  • The responses would suggest the U.S. rig count could increase another 80-90 rigs from today with the U.S. frac crew count expanding by another 20 fleets.  We model a ~100 rig count improvement through YE’22 and had assumed a similar improvement in frac activity, thus the feedback is largely consistent with our modeled view.  However, one cannot dismiss the strength of natural gas prices and continued strength of oil prices.  Moreover, our sample size of private E&P’s is relatively light and those companies, we submit, are more likely to capitalize on the current commodity price environment.

  • Of the 48 respondents, 22 are private companies who presently operate 61 rigs while 26 are public companies operating 188 rigs.

  • Again, we recognize our survey sample is light on private companies, thus a key reason for an upwards bias to our forecast.

  • Private E&P’s account for 30 of the 107 frac crews in our tally.

  • Of the expected 43 rig count increase, 16 rigs are from private companies while 27 rigs are from public companies.  This implies a ~26% increase in our surveyed private E&P’s rig activity and a ~15% increase in our public E&P’s activity.

  • Five E&P companies account for ~50% of the 43-rig count improvement.

  • A large number of the rig additions are likely to occur in Q4.

  • There are 14 E&P’s who expect to increase completion activity while we understand 6 E&P’s may reduce completion activity (likely a function of DUC drawdowns in 2021).  The rest are flat.

  • What makes the completion query a bit sketchy is companies addressed current frac crews today vs. next year, but some noted a spot crew may be needed here-or-there next year.  Makes us have a slight upwards bias to our view.  Also, some E&P’s did not employ a dedicated frac crew in 2021, but their completion activity should be busier in 2022, but perhaps still not enough to justify a dedicated crew.  Hard to model.

  • Our E&P feedback included 17 E&P’s who we believe have no Permian exposure.

  • 21 of the 48 respondents have two or less rigs running today.

  • Most of the additions are expected to be Permian-directed, although we estimate 8-10 of the incremental 43 rigs are likely destined for the Haynesville.

  • Private company feedback varies, but not all are in growth mode.  Two companies will reduce activity in 2022 while one recently slowed activity.  In one case, the company accelerated activity in 2021 given low service costs but will now focus on production work in 2022.  This company recently secured a price quote for a CT unit.  In November 2020, it paid $900/hour.  The recent quote is $1,400/hour, a 55% increase.  Another private company recently reduced its rig count by two rigs as it will work through the DUC balance.  A third private who will release a rig did not explain why.

  • Our tally includes discussions with three E&P’s who were unable/unwilling to share a specific 2022 outlook.  That’s fine.  The first company did note a doubling of its rig count during 2021.  It also mentioned a desire to limit production growth to low-to-mid single digits next year.  In this case, knowing the magnitude of this year’s activity ramp, we are assuming this company’s rig count is flat from today as we don’t know how one could keep modest production growth with such a large gain in drilling activity.  We are making a similar assumption with respect to its frac activity.  For the second E&P, it indicated 2022 consensus expectations was a good starting point which did not necessarily cause heart palpitations for our contact.  The third E&P simply didn’t want to opine on 2022, but did reiterate the capital discipline narrative so we assume flat from here.  The collective point is we do make some educated assumptions for certain E&P companies, thus a potential risk to our view.

  • A few E&P contacts note plans to reduce Q4 frac activity, but also expect to pick these crews back up in Q1.  Recall from our Q2 earnings summaries that numerous E&P companies provided Q3/Q4 capex forecasts which point towards a Q4 slowdown.

  • Two E&P companies with whom we did not speak are purportedly in a “blow down” strategy.  Other E&P’s familiar with their situation report these companies ramped activity hard in 2021, but will likely drill through inventory this year, thus the rig counts for these two E&P players could fall.  Collectively, the two companies run ~10 Permian rigs.  Again, industry speculation, but something we will try to dig into.

  • On the other hand, we visited with two new E&P’s who have no rigs/crews running today.  One recently secured acreage while the other is looking hard at acreage opportunities.  Both would expect to add a rig in 2022.  In another case, a new private E&P with whom we did not speak will also commence operations in 2022.  A completion tools sales contact has lined up work with this new provider.  We don’t include a rig or frac crew estimate for this company, but it’s reasonable to assume it will have at least one rig and crew at some point in 2022 otherwise why would it need completion tools.

  • The concept of new companies is encouraging as it creates new growth opportunities, but it’s not clear how many are out there.  To the extent large E&P’s divest acreage, this creates the opportunity as buyers would presumably go to work.

  • Drillable inventory came up in several discussions.  One reason some private E&P companies are believed to be slowing their ramp is the need to not drill through their inventory.  A lack of inventory could deter potential suitors.  Other E&P companies may be potential IPO candidates, thus the ability to show free cash flow and capital discipline might be important to would be investors.  Consequently, one can’t assume all privates will be pedal-to-the-metal.

  • Multiple public E&P’s note a desire to have emission-friendly frac equipment.  All understand supply is essentially sold-out; therefore, companies building new capacity today shouldn’t have too much trouble finding a home for it.  Frac companies with emission-friendly equipment can and will get net pricing increases, in our view.

  • Additionally, with the U.S. frac crew count expected to increase, the threat of new frac start-up’s is diminished, but shouldn’t be overlooked. That said, consolidation, in our view, is still a critical step to a more pronounced pricing recovery in all of OFS.

  • Most of our E&P contacts are budgeting service cost inflation of 10% to as much as 20% next year (most closer to ~10%).  Essentially all report service cost increases already.  OCTG/steel cost creep is the biggest culprit.  Therefore, a portion of budget increases reflect higher costs.  Companies hope efficiency gains can mitigate some of the cost creep.

  • Permian contacts report employees from East Texas are electing to take work back home given the rise in Haynesville activity.  This makes a bad labor situation worse.

  • As noted at the onset of this commentary, the responses are confidential.

Investor Sentiment:  Largely unchanged per our public E&P friends.  IR teams continue to report large shareholders still seek free cash flow yield over production growth; therefore, this likely restrains activity growth.  All, however, agree the best returns are new D&C activity, but you do what shareholders want.  Also, all generally agree equity prices would be negatively impacted by a shift towards greater production growth.  If investors were to reward an E&P for aggressive growth, then the capex budgets would be revisited.  Also, some contacts note the right-sizing effect of the downturn also limits growth.  Specifically, if a company were to aggressively increase activity, more people would be required.  Finding people remains tough and returns today are good.  Consequently, why mess with a good thing and deal with the hassles of bulking up, particularly after having slashed/burned just one year ago today.  Moreover, if investors really believe oil prices have a terminal value of zero, then don’t add more people, but instead maximize cash flow today.

BKR Land Rig Count:  Small 2 rig increase this Friday to 497 rigs.

KLX Energy Services:  Reported fiscal Q2 earnings on Friday.  Q2 revenue improved 23% q/q to $112M with adjusted EBITDA totaling ~$600,000.  This marks the first EBITDA positive quarter since Q1’20.  Q3 revenue is guided to improve 8-12% q/q while EBITDA margins exited Q2 in the low-to-single digits, thus one would assume a modest uplift in margins q/q in Q3.  Notable comments:  First, KLXE is focused on continued pricing improvement and sees further gains this year.  The company’s dissolvable plugs business witnessed a 41% q/q improvement.  Interestingly, KLXE called out its costs associated with COVID, noting YTD spend of $600,000 associated with testing and treatment.  Management noted efforts to incentivize employees to get vaccinated.  Also, the company foresees continued gains in ETX/Haynesville activity, a comment consistent with our rig count queries.  Finally, KLXE is a good example of what can happen with OFS M&A as the company is now one year removed from the KLXE/QES merger.  According to management, the company achieved nearly $50M in synergies.  Long term debt is $274M.  Cash is $39M.  Capex for 2021 is budgeted at $14M to $16M.  The company is getting rid of some non-core assets and should receive a modicum of cash from asset sales.

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