DEP Update:  Just back from Midland (observations below) and heading to Denver tomorrow for two days of meetings and a small group dinner.  One open slot in Denver if anyone is feeling charitable with their time.  Speaking of charity and good deeds, for those who would like to take stress out of our lives, please take a moment to register for the THRIVE Energy conference.  Last year we saw a doubling of our registrations in the final week – leading up to that moment, we were having heart palpitations, fearing no one would show up. We’d like to avoid that stress this year, so pretty please join the ~330 folks from ~154 companies who have already registered and take two minutes to complete the registration link.  If you need the link, simply email us and we will gladly send it your way (assuming, of course, you are a client/sponsor/friend of firm since some folks still forward our note).  On the topic of the conference, we are attaching the latest agenda – please review as the content is strong.  To our speakers and sponsors, we are very grateful for your continued support.

Permian Observations:  Quick trip this past week to Midland with two themes most topical.  First, questions surrounding the continued decline in DUC inventories and the impact to completion activity later this year.  Second, high-level speculation on Permian oil production estimates and their respective achievability.  We’ll dig into Theme #1 first which is the perceived DUC conundrum.  Per the EIA, Permian DUCs totaled 1,446 as of December 2021.  This is the lowest level since early 2017 and compares to DUCs of ~3,000 at the end of December 2020.  Several smart E&P contacts this week raised concerns about the potential for slowing Permian completion activity later this year given declining DUC inventories for some operators.  However, with each of the operators with whom we updated (who collectively run ~15% of the Permian active crew count), none of them intend to reduce completion activity this year.  Moreover, in three cases the E&P companies actually intend to sporadically pick up spot crews.  Thus the concern about Permian DUCs doesn’t necessarily correspond to their own situation.  Now, to be fair, a survey of only ~15% of the working frac crews is hardly comprehensive.  But we would be remiss to not point out the significant number of small E&P companies who have recently added rigs during the past few months.  Presumably, those wells being drilled today will most likely result in a call for incremental spot frac crews later this year.  From chatting with industry contacts, it would appear there could be as many as 35+ E&P’s presently drilling today who do not have an active frac crew (15+ E&P names which are new to us).  Assuming this field commentary is correct and knowing oil prices today are well above any budgetary price deck used when those rigs went to work, it is a safe bet more frac demand will develop.   Consequently, while the EIA DUC data is interesting and gives reason to believe a potential demand decrease for frac could develop (something we previously opined on a couple months ago), the on-the-ground observations and discussions lead us to disagree – at least at this point.

As for Theme #2, multiple E&P contacts are questioning Permian oil production estimates.  First, DEP doesn’t model Permian production, at least not yet, so we aren’t here to agree/disagree this evening.  Frankly, we just returned from Midland and haven’t had time to even review such industry estimates, but when quality E&P execs raise questions, we pay attention.  Here are the two key reasons for the theory.  First, multiple E&P contacts claim the recent rig additions are going towards Tier 2 acreage, thus it is unlikely those wells will enjoy similar well productivity results as Tier 1 acreage.  Second, some of the drilling is moving towards more infield development and these wells, according to contacts, are not as productive.  Both ideas, on the surface sound reasonable, but here’s what piqued our interest.  Our E&P contacts remain bullish crude prices with some avoiding additional hedges given a belief price will go higher.  So, it’s not just a theory, rather it’s a theory with real money behind it.


Perspectives on the U.S. Frac Market:  This past week we reached out to a basket of E&P, pressure pumping and capital equipment friends.  Time limitations and travel prevented us from hitting everyone, but we spoke to sufficient number of contacts such that our views on the market were reaffirmed.  We will dive into the specifics below, but for those wanting the CliffsNotes version, we maintain our call for stable-to-slightly improving activity.  Our current tally of active fleets stands at ~240 fleets.  This includes vertical fleets and is not a “working” or “fully-utilized” count as that changes every day.  Our gut says a true working number would be in the 220-230 vicinity.  Looking forward, we believe the industry will see an incremental ~15-20 fleets over the course of the year – likely some spikes in the summer with the normal Q4 end-of-year slowdown.  While oil prices and returns would argue for a sharper ramp, the continued call on capital discipline is real and the public c-suite is thus far abiding.  Lastly, we expect to see more announcements of new frac equipment, notably electric fleets.  We further expect many of these fleets to use natural gas reciprocating engines as the power source.  Tier 4 dual fuel upgrades will also persist as the fuel savings to E&Ps should justify the conversions.  What will likely serve as the greatest headwind for electric fleet deployment will be the slow contracting process as many E&P companies remain reluctant to sign long-term take-or-pay contracts while funding challenges present a headwind for the frac companies.  In time, however, we believe ESG pressures will expedite the development, but in the interim, Tier 4 dual fuel will serve as an effective bridge.

U.S. Supply:  Our frac template assumes total industry horsepower of 20.5M which, in theory, distills into a potential total of 400 fleets, of which ~240 are considered active and ~160 would be considered stacked.  Here’s where the data gathering gets tricky.  First, our stacked tally is likely very misleading as most of the stacked horsepower will never return to the market.  So why include it?  Simple. The large players continue to report total fleet sizes which are more than their true working counts.  Therefore, until the industry permanently removes it from their disclosures, we will keep it, although we don’t believe it.  In addition to the stacked horsepower from existing companies, we also include the assets from businesses which have shut down (i.e., PumpCo, Legend, Oasis, BJS, etc.) although we attempt to adjust these totals when we can track where that horsepower has been sold/redeployed.  The reason we keep this equipment in our tally is a large portion of the assets have been sold to new start-ups, to equipment rental companies or to builders who seek to rebuild/resell the equipment.  So, in a way, this equipment is much like kudzu.  You cut it and think it goes away, but then it comes right back.  The consequence of presenting so much idle capacity is it gives a false impression that this equipment can readily return to service.  That is an incorrect view as labor constraints, supply chain and a simple need to make money will keep most of that horsepower forever at rest.  One day, we hope, the larger players will revise their horsepower totals to improve the data quality and right industry misperceptions.

Of note, our U.S. frac supply tally includes 37 companies who we believe actively participate in the market.  This includes companies who focus solely on the vertical frac market.  We are tracking one company which may soon entering the vertical market in the Permian while two others may enter later this year with electric designs, thus barring M&A, we would expect the supplier list to move over 40 companies by year-end.   Also, our supply tally includes our estimate of ~18 electric / turbine driven fleets, 43 fleets which are Tier 4 dual fuel capable (including some fleets which have third-party dual fuel kits), and ~40 Tier 2 dual fuel fleets.  We acknowledge one’s fleet status can change, so give us some wiggle room on these tallies.  We do, however, feel we are in the ballpark.

A geographic breakdown of our estimated active fleets is below while our excel file is available to clients upon request.

U.S. Active Fleets
Region Fleets
Permian Basin 111
Marcellus 28
Eagle Ford 27
Haynesville 22
Rockies 23
Bakken 13
Mid-Con 14
Other 1
  Total 239

Source: DEP estimates, Industry Sources

Demand Outlook:  Our frac-demand forecast is rig-count driven.  It incorporates a myriad of assumptions with respect to forward rig counts, type of rig activity, stages/day, etc.  It’s a top-down approach to arriving at implied demand and admittedly, it has plenty of room for error.  Nevertheless, in recent quarters, the model has directionally served us well.  Of course, we do our best to apply a bottoms-up approach by querying both frac companies and more importantly, E&P companies as to each player’s respective outlook for completion crew activity.  Right now, we model the U.S. rig count averaging ~584 rigs in Q1’22, already feels light given the rig count as of Friday was 584 rigs.  For Q2’22, we model an average of 623 rigs with the rig count exiting 2022 around 650-675 rigs.  We do model 2023 and beyond, but let’s not kid ourselves, no one has a clue.  That said, if the forward curve for WTI and nat gas are directionally correct (i.e., ~$73/bbl in 2023 and ~$3.50/MMBtu) then we would suspect a continued, modest upward trajectory in 2023 materializes with the rig count exceeding 700 rigs in the out years.  As for the frac crew forecast, we believe the active count is ~240 crews today, which we would estimate implies a working crew count in the 220-230 vicinity.  For the balance of the year, we believe the active/working crew count rise an additional 15-20 fleets.

Newbuild Prospects:  We estimate at least 24 new fleets are on order, most of which will be either electric and/or direct-drive turbine.  Tier 4 dual-fuel conversions will continue and while, in our view, these are essentially new units, they will almost entirely be used to replace existing Tier 2 capacity, thus we do not call out these upgrades as newbuilds.  Yes, this is debatable, but what we are trying to isolate as best as we can is what we foresee as either expansionary fleets or newer, leading-edge technology.  As for the expected newbuilds, most we believe come from leading players such as HAL, LBRT, BJ Energy Solutions, ProFrac, and U.S. Well Services.  As noted in last week’s note, we contend any new electric or direct-drive turbine fleets from BJ Energy Solutions, U.S. Well, Evolution and/or Catalyst are expansionary, thus we peg that estimate at ~12 fleets.  New fleets from players such as HAL, LBRT and Pro Frac presumably will be replacement capacity (we hope).  Lastly, there are two new companies which we believe are likely to get a contract/funding in 2022 and who will enter the electric frac market, thus in our newbuild table we have included two fleets in the other category.  So, all this said, we estimate expansionary newbuild activity will include as many as 14 fleets over the next 4-5 quarters, subject to supply chain and funding.

Emerging Competition:  Previous notes have highlighted new entrants into the U.S. frac market, essentially all who have commenced operations with purchases of legacy equipment.  Our list includes potentially 10-12 total fleets between 7 companies.  Specifically, entities which we believe have active frac crews include: Pure-Frac, Grappler Pumping Services, Express Pressure Pumping, Straitline Pressure Pumping, Pharoah Energy Services, Acquire Oilfield Solutions and Integrity Energy Services.  We also believe Regiment LLC now has sufficient frac horsepower to constitute a new fleet. We further suspect this year could see the emergence of potentially two new electric frac companies.  One enterprise, which we’ll name in an upcoming piece, is reported to have tested its design during Q4 while the other enterprise we believe is securing financing to enter the market.  Both companies enjoy seasoned leadership with significant OFS experience.  If our hunch on these two players is correct, we believe these enterprises could collectively each deploy one fleet before Q1’23.  Finally, during our industry calls this week, we uncovered a Louisiana pump down company which purportedly has accumulated enough pumps whereby the company purportedly intends to open a vertical frac operation in/around the Texas Panhandle.  Once we confirm this is a real player, we’ll adjust our table accordingly.

Individually, none of these emerging enterprises represent a material risk to the U.S. frac market today.  But if our active tallies are correct, these businesses collectively run ~7-8 fleets, potentially rising to as many as ~10-12 fleets later this year.  That’s about a 5% market share with most of the additions being legacy Tier 2 equipment.  The emergence of these companies is problematic from the standpoint that the trend disrupts the recent consolidation/industry normalization process which kicked off several quarters ago.  The good news is we track several small players who are actively seeking to exit the business, thus more consolidation appears likely.

Seneca Resources/NexTier Emissions Study.   Several weeks ago, Seneca Resources published a slide deck highlighting the results from a joint study it conducted with NexTier.  The study included a comprehensive review of emissions from various frac solutions, including Tier 2, Tier 4, Dual-Fuel, Turbine and natural gas reciprocating engine solutions.  The study incorporated real life data measured/analyzed by two different entities: Air Hygiene and West Virginia University.  We took particular interest in this presentation as the data was published by an E&P, not a service company and not an OEM.  This, in our view, provides a more objective perspective (with all due respect to our service/cap equipment friends).  In a nutshell, here are the observations and what stood out to us.

First, fuel savings were quantified.  Seneca presented the annual fuel costs for an assumed frac spread with a set number of pumping hours.  In this case, 22,000HP with 4,000 pumping hours.  Using a traditional 100% diesel solution, the annual fuel costs were estimated at $16M.  Employing a dual-fuel solution with 50% substitution would yield $11M in fuel costs while a dual fuel solution with 70% substitution (i.e., Tier 4 dual fuel) would yield $8.5M in annual fuel costs.  The lowest fuel costs come from 100% gas fueled fleet (i.e., turbine or natural gas recip engine) which amount to an estimated $6M per year.   True, this is one scenario, but the larger point, we submit, is validation that the transition to nat gas powered equipment potentially offers material fuel cost savings to the E&P.  This is not a surprise as multiple E&P’s such as EQT, CNX have cited those savings before.

The second item which stood out is the comparison of the relative emission reductions from each solution.  The winner in the Seneca/NexTier study is the natural gas reciprocating engine solution.  What jumped out, however, was the relative similarity in emission reductions (CO2e) with Tier 2 and Tier 4 dual fuel engines.  And while the results suggest the emission reductions from turbines underperformed relative to other solutions, we note the data was for the larger 35MW industrial turbine solution.  So as to not offend any of our turbine friends, we visited with three contacts knowledgeable about both the natural gas recip engine solutions as well as the turbine solutions.  All agree the industrial size turbine can be a viable solution, but the contacts contend viability requires the industrial turbine to generate above-average utilization (i.e., 500+ pumping hours/month) in order to achieve similar emission reductions as the reciprocating engine solution.  That’s not inconceivable but is still rare with most frac operations.  As for the fuel savings, all agree it is on par with the gas reciprocating engines.  Recall, several frac companies have publicly discussed a preference for the gas genset solution over turbines.  In fact, we believe some frac companies have actually sold and/or attempted to sell their industrial turbines.  That, in our view, is another validating anecdote which supports the Seneca/NexTier study.

Dynamis Power Solutions.  In perhaps one more validation of the Seneca study, this past week Dynamis Power Solutions announced it will offer its own 2.5MW continuous-duty power solution, a product which we believe incorporates natural gas recip engine technology.  The move by Dynamis does not indicate an issue with turbine technology, but rather broadens the company’s product portfolio.  It is our understanding the first DE2.5 system will hit the field in Q2, most likely on a new frac spread.  Presumably, this will be the first of many given our belief the electrification process will continue to unfold.  We would also suspect these power solutions will similarly be adopted by land drilling contractors as well.

BKR U.S. Land Rig Count:  +3 rigs w/w to 584 rigs.  If we keep the current QTD pace of ~4.5 rigs/week, we’ll exit Q1’22 at ~625 rigs and DEP will be on the verge of once again beating a smart E&P exec on the rig count trajectory – the over/under is 625 at the end of March, a level set back in the summer of 2021.  BTW – we took the over.


As always, these notes are not investment advice.  We have lots of opinions, just not investment opinions on the stocks.


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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