Happy Valentine’s Day.  We submit a great way to kick off a romantic Valentine’s Day dinner is with a couple’s review of DEP’s latest thoughts, thus we send out our note an hour early this evening.

Brief note this weekend as we provide high level thoughts from another Permian trip as well as opine on current rig activity and select company earnings.  We hope everyone will be safe the next few days given the winter weather carnage afflicting the state of Texas.  After reading a number of LinkedIn posts which show harsh field condition photos, the DEP team is reminded just how thankful we all should be for the thousands of oil and gas workers whose hard work provides us with the energy needed to stay warm this winter.

THRIVE Energy Conference Update.  Registered attendees now total ~670 individuals from 301 companies.  We will close registration on Wednesday, so if you want to attend, please register.  The invite should be in your inbox somewhere, but if you can’t find it, please email me directly and I’ll send it again.  As noted in prior Sunday notes, we do not intend to offer onsite registration and if we reluctantly do, be prepared for a long line.  Event will be held on February 25-26th at Minute Maid Park.

Permian Observations.  We drove over to the Permian again this past week.  When one considers the frequency of our visits, there are many times our trips do not yield anything incremental.  Frankly, that was the case this past week.  Nevertheless, here are a few takeaways.  First, E&P companies continue to anticipate service cost increases, but to date, the increases have been limited.  Areas where costs appear to be rising the fastest are OCTG. In some cases, E&P’s acknowledge receipt of service company price increases, but in select instances, they then put the work back out for bid and have switched providers. Second, we had several companies note issues with sand procurement as three regional mines purportedly had production issues.  We were told this led to a sand shortage for certain companies which caused a spike in spot pricing.  Consequently, we were told of several frac crews shutting down as the E&P companies didn’t want to proceed with elevated spot sand price purchases, but instead opted to wait until the production issues were resolved.  Third, weather is an issue.  Just this weekend, we learned from one frac company that it is shutting down operations due to inclement weather.  Not that DEP models any companies, but for those who do, be mindful that there could be multiple lost work days due to record cold conditions in Texas, not to mention ice and snow.  Finally, activity outlooks remain balanced.  We visited one company which will add 3-4 rigs, but others intend to hold flat.  There is also some frac crew choppiness as we met with two E&P’s that use spot frac crews and who both confirm these crews won’t operate throughout the year.  Not a big revelation, we know, but a reminder that some gains in frac activity are fleeting for select E&P’s.

Simulfracs.  This will get more airtime in 2021.  The efficiencies are real and if performed correctly, both the E&P and the service company win.  However, these projects are not for everyone as the logistics planning and equipment demands are great.  Moreover, E&P’s wishing to pursue simulfracs need to have a sizeable program with well pads having at least 4 wells (or bigger and in even increments).  A recent article in the JPT highlights a study by an energy consulting firm on the simulfrac market.  On the one hand, the reporting is helpful, but we question some of the data.  The consulting firm’s study, at least as presented in the JPT article, estimates 2020 simulfrac market share by frac provider.  The estimate is based on an algorithm of well completion data, but we believe one of the purported top simulfrac market share leaders actually performed zero simulfracs in 2020 according to our field channel checks.  We will seek to confirm this shortly, but if we are correct, it’s a reason why DEP prefers actual field research over excel models.

Rig Count Observations.  The BKR U.S. Land Rig count rose again, up 4 rigs to 379 rigs.   Last week saw HP and PDS report their respective quarterly earnings and both see higher activity near-term.  HP noted it exited 2020 at 94 rigs running and is operating 103 rigs today.  It sees its working rig count at 105 to 110 rigs at the end of Q1, that’s a ~5% increase from today.  PDS meanwhile averaged 26 rigs in Q4, but is running 33 rigs today.  Management anticipates its rig count will rise 15-20% over the next few months.  Recall from previous DEP epistles, our discussions with private land drillers revealed expectations for as much as a mid-20% increase in activity – a view based on committed rigs and strong inquiries.  Dumb guy math and simple extrapolation would suggest the U.S. rig count is poised to rise another 50-75 rigs in the coming 2-3 months.  That feels right.  The bigger question is what looms beyond 1H’21.  The commodity price (i.e. WTI = $59/bbl WTI) would suggest it’s time for the E&P industry to push the accelerator, but the inconvenient truth is the persistent call for capital discipline.  Thus, this week’s Q4 E&P earnings calls will be telling.  On the docket are a smorgasbord of quality E&P’s reporting (DVN, OXY, AR, EQT, CLR, MRO, PXD, COG, CRK, LPI).  On the one hand, we hope unbridled enthusiasm is extoled with calls for rapid growth.  This is a selfish desire as it’s more fun when business is up-and-to-the-right.  Unfortunately, the upstream sector has burned investors for far too many years, thus we remain in a rebuilding trust environment.  For this reason, the right thing for E&P’s to do is nothing other than reiterate a commitment to discipline with an intent to capitalize on this year’s commodity price uplift by way of special dividends, debt reduction and perhaps, a modicum of share buybacks.  As for the DEP rig count forecast, we intend to update it post our THRIVE conference.  However, as we have stated in at least one prior note, we know the forecast is stale.  Presently, the 2H’21 DEP forecast calls for an average of ~415 rigs (using BKR as our proxy), but the reality is we will likely be in the 450-500 range.  Moreover, if WTI prices stay in the $50+ range (2022 strip at ~$52/bbl) and nat gas at ~$2.75+, watch out as we would expect the rig count to march over 600 rigs – discipline be damned.

HP Fiscal Q1 Earnings:  We’ll focus on HP’s North American Solutions segment as this is where the U.S. land rigs are housed.  Revenue for fiscal Q1 totaled $202M, up from $149M in fiscal Q4.  Gross margin improved modestly to $45M from $39M (burdened by $10M of rig reactivation costs).  Top line gains driven by higher activity as HP’s rig count averaged 81 rigs vs. 65 rigs in the prior quarter.  Looking forward, the segment will see the working rig count migrate from 103 rigs today to as much as 110 rigs by the end of March.   Revenue guidance not provided, but gross margins should improve to $60-70M.  The company noted it will incur $6M of rig reactivation costs this quarter, pegging typical reactivation costs at as much as $500,000 per rig.  Something to consider: If one assumes leading edge Super Spec dayates are in the high-teen’s and one’s operating costs are the $13,000/day vicinity, a reasonable cash margin construct falls in the $5,000/day to maybe high-single digits (ex: technology add-on’s, performance fees).  Let’s be generous and assume $10,000/day cash margins.  This means at a $500,000/rig reactivation cost, the driller doesn’t recoup its money until after ~50-60 days of operation.  Very simplistic approach, but one that would seemingly suggest a driller should keep idle rigs against the fence unless decent visibility of work supports the reactivation.  Other: HP’s FY’21 capex budget is set at 85M to $105M.  During the fiscal Q1, HP spent $14M, thus an acceleration in spending, albeit small, will unfold as HP sees its activity rise.  HP noted that it’s AutoSlide technology is deployed on ~25-30% of its fleet while its performance-based contracts have similar percentages.

PDS Q4 Earnings:  Continued execution from our perspective as PDS set out on a mission a long time ago to focus on balance sheet improvement and that’s what has transpired.  The company reduced debt by $171M in 2020 and a total reduction of $550M during the past three years.  This commitment to balance sheet improvement will continue in 2021 with PDS establishing a goal to reduce debt by another $100M to $125M.  Operationally, PDS saw its U.S. rig count average 26 rigs in Q4, up from 21 rigs in Q3.  The current working U.S. rig count is 33 rigs with management noting an expectation for a 15-20% improvement over the next several months.  U.S. cash margins in Q4 were $11,158/day.  Like HP, PDS continues to develop and expand its technology footprint.  The company’s AlphaAutomation grew handsomely in 2020, employed on ~41% of wells in 2020 vs. ~23% in 2019.  The Alpha technology add-on’s drive efficiency and provide a valuable incremental revenue contribution above and beyond the dayrate.  One segment’s performance which stood out this quarter is the PDS well service business.  While rig hours were ~30% lower on a y/y basis, segment adjusted EBITDA margins jumped ~350bp to 22.4%, a reflection of the company’s continued turnaround/restructuring efforts.  Not sure how much the CEWS enhanced this segment’s results, if any, however.  That said, management is optimistic about a healthy recovery in 2021 for this segment.  Other: Q4 capex came in at $23M.  The 2021 capex budget is set at $54M which is roughly 2/3 maintenance related.  Cash ended the year at $109M while total debt stands at $1.2B.

Reminder.  Our company comments are not investment advice.

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Daniel Energy Partners is pleased to announce the publication of its first market research note. In this note, we reached out to executives across the oil service and E&P sectors to gauge leading edge sentiment.

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